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Sample records for permeable oil reservoirs

  1. Advantageous Reservoir Characterization Technology in Extra Low Permeability Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Yutian Luo

    2017-01-01

    Full Text Available This paper took extra low permeability reservoirs in Dagang Liujianfang Oilfield as an example and analyzed different types of microscopic pore structures by SEM, casting thin sections fluorescence microscope, and so on. With adoption of rate-controlled mercury penetration, NMR, and some other advanced techniques, based on evaluation parameters, namely, throat radius, volume percentage of mobile fluid, start-up pressure gradient, and clay content, the classification and assessment method of extra low permeability reservoirs was improved and the parameter boundaries of the advantageous reservoirs were established. The physical properties of reservoirs with different depth are different. Clay mineral variation range is 7.0%, and throat radius variation range is 1.81 μm, and start pressure gradient range is 0.23 MPa/m, and movable fluid percentage change range is 17.4%. The class IV reservoirs account for 9.56%, class II reservoirs account for 12.16%, and class III reservoirs account for 78.29%. According to the comparison of different development methods, class II reservoir is most suitable for waterflooding development, and class IV reservoir is most suitable for gas injection development. Taking into account the gas injection in the upper section of the reservoir, the next section of water injection development will achieve the best results.

  2. Microbial mineral illization of montmorillonite in low-permeability oil reservoirs for microbial enhanced oil recovery.

    Science.gov (United States)

    Cui, Kai; Sun, Shanshan; Xiao, Meng; Liu, Tongjing; Xu, Quanshu; Dong, Honghong; Wang, Di; Gong, Yejing; Sha, Te; Hou, Jirui; Zhang, Zhongzhi; Fu, Pengcheng

    2018-05-11

    Microbial mineral illization has been investigated for its role in the extraction and recovery of metals from ores. Here we report our application of mineral bioillization for the microbial enhanced oil recovery in low-permeability oil reservoirs. It aimed to reveal the etching mechanism of the four Fe (III)-reducing microbial strains under anaerobic growth conditions on the Ca-montmorillonite. The mineralogical characterization of the Ca-montmorillonite was performed by Fourier transform infrared spectroscopy, X-ray powder diffraction, scanning electron microscopy and energy dispersive spectrometer. Results showed that the microbial strains could efficiently reduce Fe (III) at an optimal rate of 71 %, and alter the crystal lattice structure of the lamella to promote the interlayer cation exchange, and to efficiently inhibit the Ca-montmorillonite swelling at an inhibitory rate of 48.9 %. Importance Microbial mineral illization is ubiquitous in the natural environment. Microbes in low-permeability reservoirs are able to enable the alteration of the structure and phase of the Fe-poor minerals by reducing Fe (III) and inhibiting clay swelling which is still poorly studied. This study aimed to reveal the interaction mechanism between Fe (III)-reducing bacterial strains and Ca-montmorillonite under anaerobic atmosphere, and to investigate the extent and rates of Fe (III) reduction and phase changes with their activities. Application of Fe (III)-reducing bacteria will provide a new way to inhibit clay swelling, to elevate reservoir permeability, and to reduce pore throat resistance after water flooding for enhanced oil recovery in low-permeability reservoirs. Copyright © 2018 American Society for Microbiology.

  3. Compositional simulations of producing oil-gas ratio behaviour in low permeable gas condensate reservoir

    OpenAIRE

    Gundersen, Pål Lee

    2013-01-01

    Master's thesis in Petroleum engineering Gas condensate flow behaviour below the dew point in low permeable formations can make accurate fluid sampling a difficult challenge. The objective of this study was to investigate the producing oil-gas ratio behaviour in the infinite-acting period for a low permeable gas condensate reservoir. Compositional isothermal flow simulations were performed using a single-layer, radial and two-dimensional, gas condensate reservoir model with low permeabili...

  4. Oil recovery enhancement from fractured, low permeability reservoirs. [Carbonated Water

    Energy Technology Data Exchange (ETDEWEB)

    Poston, S.W.

    1991-01-01

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990-1991 year may be summarized as follows: Geological Characterization - Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. The results of these efforts were directly applied to the development of production decline type curves applicable to a dual-fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. Shear-wave splitting concepts were used to estimate fracture orientations from Vertical Seismic Profile, VSP data. Several programs were written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods.Development of the EOR Imbibition Process - Laboratory displacement as well as Magnetic Resonance Imaging, MRI and Computed Tomography, CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery from oil saturated, low permeability rocks.Field Tests - Two operators amenable to conducting a carbonated water flood test on an Austin Chalk well have been identified. Feasibility studies are presently underway.

  5. Oil Recovery Enhancement from Fractured, Low Permeability Reservoirs. [Carbonated Water

    Science.gov (United States)

    Poston, S. W.

    1991-01-01

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990-1991 year may be summarized as follows: Geological Characterization - Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. The results of these efforts were directly applied to the development of production decline type curves applicable to a dual-fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. Shear-wave splitting concepts were used to estimate fracture orientations from Vertical Seismic Profile, VSP data. Several programs were written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods. Development of the EOR Imbibition Process - Laboratory displacement as well as Magnetic Resonance Imaging, MRI and Computed Tomography, CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery from oil saturated, low permeability rocks. Field Tests - Two operators amenable to conducting a carbonated water flood test on an Austin Chalk well have been identified. Feasibility studies are presently underway.

  6. The Hybrid of Classification Tree and Extreme Learning Machine for Permeability Prediction in Oil Reservoir

    KAUST Repository

    Prasetyo Utomo, Chandra

    2011-06-01

    Permeability is an important parameter connected with oil reservoir. Predicting the permeability could save millions of dollars. Unfortunately, petroleum engineers have faced numerous challenges arriving at cost-efficient predictions. Much work has been carried out to solve this problem. The main challenge is to handle the high range of permeability in each reservoir. For about a hundred year, mathematicians and engineers have tried to deliver best prediction models. However, none of them have produced satisfying results. In the last two decades, artificial intelligence models have been used. The current best prediction model in permeability prediction is extreme learning machine (ELM). It produces fairly good results but a clear explanation of the model is hard to come by because it is so complex. The aim of this research is to propose a way out of this complexity through the design of a hybrid intelligent model. In this proposal, the system combines classification and regression models to predict the permeability value. These are based on the well logs data. In order to handle the high range of the permeability value, a classification tree is utilized. A benefit of this innovation is that the tree represents knowledge in a clear and succinct fashion and thereby avoids the complexity of all previous models. Finally, it is important to note that the ELM is used as a final predictor. Results demonstrate that this proposed hybrid model performs better when compared with support vector machines (SVM) and ELM in term of correlation coefficient. Moreover, the classification tree model potentially leads to better communication among petroleum engineers concerning this important process and has wider implications for oil reservoir management efficiency.

  7. Oil recovery enhancement from fractured, low permeability reservoirs. Annual report 1990--1991, Part 1

    Energy Technology Data Exchange (ETDEWEB)

    Poston, S.W.

    1991-12-31

    Joint funding by the Department of Energy and the State of Texas has Permitted a three year, multi-disciplinary investigation to enhance oil recovery from a dual porosity, fractured, low matrix permeability oil reservoir to be initiated. The Austin Chalk producing horizon trending thru the median of Texas has been identified as the candidate for analysis. Ultimate primary recovery of oil from the Austin Chalk is very low because of two major technological problems. The commercial oil producing rate is based on the wellbore encountering a significant number of natural fractures. The prediction of the location and frequency of natural fractures at any particular region in the subsurface is problematical at this time, unless extensive and expensive seismic work is conducted. A major portion of the oil remains in the low permeability matrix blocks after depletion because there are no methods currently available to the industry to mobilize this bypassed oil. The following multi-faceted study is aimed to develop new methods to increase oil and gas recovery from the Austin Chalk producing trend. These methods may involve new geological and geophysical interpretation methods, improved ways to study production decline curves or the application of a new enhanced oil recovery technique. The efforts for the second year may be summarized as one of coalescing the initial concepts developed during the initial phase to more in depth analyses. Accomplishments are predicting natural fractures; relating recovery to well-log signatures; development of the EOR imbibition process; mathematical modeling; and field test.

  8. Bacterial community diversity in a low-permeability oil reservoir and its potential for enhancing oil recovery.

    Science.gov (United States)

    Xiao, Meng; Zhang, Zhong-Zhi; Wang, Jing-Xiu; Zhang, Guang-Qing; Luo, Yi-Jing; Song, Zhao-Zheng; Zhang, Ji-Yuan

    2013-11-01

    The diversity of indigenous bacterial community and the functional species in the water samples from three production wells of a low permeability oil reservoir was investigated by high-throughput sequencing technology. The potential of application of indigenous bacteria for enhancing oil recovery was evaluated by examination of the effect of bacterial stimulation on the formation water-oil-rock surface interactions and micromodel test. The results showed that production well 88-122 had the most diverse bacterial community and functional species. The broth of indigenous bacteria stimulated by an organic nutrient activator at aerobic condition changed the wettability of the rock surface from oil-wet to water-wet. Micromodel test results showed that flooding using stimulated indigenous bacteria following water flooding improved oil recovery by 6.9% and 7.7% in fractured and unfractured micromodels, respectively. Therefore, the zone of low permeability reservoir has a great potential for indigenous microbial enhanced oil recovery. Copyright © 2013 Elsevier Ltd. All rights reserved.

  9. Reservoir rock permeability prediction using support vector regression in an Iranian oil field

    International Nuclear Information System (INIS)

    Saffarzadeh, Sadegh; Shadizadeh, Seyed Reza

    2012-01-01

    Reservoir permeability is a critical parameter for the evaluation of hydrocarbon reservoirs. It is often measured in the laboratory from reservoir core samples or evaluated from well test data. The prediction of reservoir rock permeability utilizing well log data is important because the core analysis and well test data are usually only available from a few wells in a field and have high coring and laboratory analysis costs. Since most wells are logged, the common practice is to estimate permeability from logs using correlation equations developed from limited core data; however, these correlation formulae are not universally applicable. Recently, support vector machines (SVMs) have been proposed as a new intelligence technique for both regression and classification tasks. The theory has a strong mathematical foundation for dependence estimation and predictive learning from finite data sets. The ultimate test for any technique that bears the claim of permeability prediction from well log data is the accurate and verifiable prediction of permeability for wells where only the well log data are available. The main goal of this paper is to develop the SVM method to obtain reservoir rock permeability based on well log data. (paper)

  10. The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs: a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie Formation in Dongying Sag

    DEFF Research Database (Denmark)

    Yang, Tian; Cao, Ying-Chang; Wang, Yan-Zhong

    2016-01-01

    The relationships between permeability and dynamics in hydrocarbon accumulation determine oilbearing potential (the potential oil charge) of low permeability reservoirs. The evolution of porosity and permeability of low permeability turbidite reservoirs of the middle part of the third member...... facies A and diagenetic facies B do not develop accumulation conditions with low accumulation dynamics in the late accumulation period for very low permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock. Also...

  11. The Hybrid of Classification Tree and Extreme Learning Machine for Permeability Prediction in Oil Reservoir

    KAUST Repository

    Prasetyo Utomo, Chandra

    2011-01-01

    the permeability value. These are based on the well logs data. In order to handle the high range of the permeability value, a classification tree is utilized. A benefit of this innovation is that the tree represents knowledge in a clear and succinct fashion

  12. Investigating the effects of rock porosity and permeability on the performance of nitrogen injection into a southern Iranian oil reservoirs through neural network

    Science.gov (United States)

    Gheshmi, M. S.; Fatahiyan, S. M.; Khanesary, N. T.; Sia, C. W.; Momeni, M. S.

    2018-03-01

    In this work, a comprehensive model for Nitrogen injection into an oil reservoir (southern Iranian oil fields) was developed and used to investigate the effects of rock porosity and permeability on the oil production rate and the reservoir pressure decline. The model was simulated and developed by using ECLIPSE300 software, which involved two scenarios as porosity change and permeability changes in the horizontal direction. We found that the maximum pressure loss occurs at a porosity value of 0.07, which later on, goes to pressure buildup due to reservoir saturation with the gas. Also we found that minimum pressure loss is encountered at porosity 0.46. Increases in both pressure and permeability in the horizontal direction result in corresponding increase in the production rate, and the pressure drop speeds up at the beginning of production as it increases. However, afterwards, this pressure drop results in an increase in pressure because of reservoir saturation. Besides, we determined the regression values, R, for the correlation between pressure and total production, as well as for the correlation between permeability and the total production, using neural network discipline.

  13. Effect of exogenous inoculants on enhancing oil recovery and indigenous bacterial community dynamics in long-term field pilot of low permeability reservoir.

    Science.gov (United States)

    Li, Jing; Xue, Shuwen; He, Chunqiu; Qi, Huixia; Chen, Fulin; Ma, Yanling

    2018-03-20

    Pseudomonas aeruginosa DN1 strain and Bacillus subtilis QHQ110 strain were chosen as rhamnolipid and lipopeptide producer respectively, to evaluate the efficiency of exogenous inoculants on enhancing oil recovery (EOR) and to explore the relationship between injected bacteria and indigenous bacterial community dynamics in long-term filed pilot of Hujianshan low permeability water-flooded reservoir for 26 months. Core-flooding tests showed that the oil displacement efficiency increased by 18.46% with addition of exogenous consortia. Bacterial community dynamics using quantitative PCR and high-throughput sequencing revealed that the exogenous inoculants survived and could live together with indigenous bacterial populations. They gradually became the dominant community after the initial activation, while their comparative advantage weakened continually after 3 months of the first injection. The bacterial populations did not exert an observable change in the process of the second injection of exogenous inoculants. On account of facilitating oil emulsification and accelerating bacterial growth with oil as the carbon source by the injection of exogenous consortia, γ-proteobacteria was finally the prominent bacterial community at class level varying from 25.55 to 32.67%, and the dominant bacterial populations were increased by 2-3 orders of magnitude during the whole processes. The content of organic acids and rhamnolipids in reservoir were promoted with the change of bacterial community diversity, respectively. Cumulative oil increments reached 26,190 barrels for 13 months after the first injection, and 55,947 barrels of oil had been accumulated in all of A20 wells block through two rounds of bacterial consortia injection. The performance of EOR has a cumulative improvement by the injection of exogenous inoculants without observable inhibitory effect on the indigenous bacterial populations, demonstrating the application potential in low permeability water

  14. Oil recovery enhancement from fractured, low permeability reservoirs. Part 2, Annual report, October 1, 1990--September 31, 1991

    Energy Technology Data Exchange (ETDEWEB)

    Poston, S.W.

    1991-12-31

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990--1991 year may be summarized as follows: Geological Characterization -- Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. These results of these efforts were directly applied to the development of production decline type curves applicable to a dual fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. (VSP) Vertical-Seismic Profile data was used to use shear-wave splitting concepts to estimate fracture orientations. Several programs were to be written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods. Development of the (EOR) Enhanced Oil Recovery Imbibition Process -- Laboratory displacement as well as MRI and CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery of an oil saturated, low permeability core material, when compared to that of a normal brine imbibition displacement process. A study of oil recovery by the application of a cyclic carbonated water imbibition process, followed by reducing the pressure below the bubble point of the CO{sub 2}-water solution, indicated the possibility of alternate and new enhanced recovery method. The installation of an artificial solution gas drive significantly increased oil recovery. The extent and arrangement of micro-fractures in Austin Chalk horizontal cores was mapped with CT scanning techniques. The degree of interconnection of the micro-fractures was easily visualized.

  15. Oil recovery enhancement from fractured, low permeability reservoirs. Annual report, October 1, 1990--September 31, 1991, Annex 4

    Energy Technology Data Exchange (ETDEWEB)

    Poston, S.W.

    1991-01-01

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990-1991 year may be summarized as follows: Geological Characterization - Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. The results of these efforts were directly applied to the development of production decline type curves applicable to a dual-fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. Shear-wave splitting concepts were used to estimate fracture orientations from Vertical Seismic Profile, VSP data. Several programs were written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods.Development of the EOR Imbibition Process - Laboratory displacement as well as Magnetic Resonance Imaging, MRI and Computed Tomography, CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery from oil saturated, low permeability rocks.Field Tests - Two operators amenable to conducting a carbonated water flood test on an Austin Chalk well have been identified. Feasibility studies are presently underway.

  16. Production Optimization of Oil Reservoirs

    DEFF Research Database (Denmark)

    Völcker, Carsten

    with emphasis on optimal control of water ooding with the use of smartwell technology. We have implemented immiscible ow of water and oil in isothermal reservoirs with isotropic heterogenous permeability elds. We use the method of lines for solution of the partial differential equation (PDE) system that governs...... the uid ow. We discretize the the two-phase ow model spatially using the nite volume method (FVM), and we use the two point ux approximation (TPFA) and the single-point upstream (SPU) scheme for computing the uxes. We propose a new formulation of the differential equation system that arise...... as a consequence of the spatial discretization of the two-phase ow model. Upon discretization in time, the proposed equation system ensures the mass conserving property of the two-phase ow model. For the solution of the spatially discretized two-phase ow model, we develop mass conserving explicit singly diagonally...

  17. Effect of reservoir heterogeneity on air injection performance in a light oil reservoir

    Directory of Open Access Journals (Sweden)

    Hu Jia

    2018-03-01

    Full Text Available Air injection is a good option to development light oil reservoir. As well-known that, reservoir heterogeneity has great effect for various EOR processes. This also applies to air injection. However, oil recovery mechanisms and physical processes for air injection in heterogeneous reservoir with dip angle are still not well understood. The reported setting of reservoir heterogeneous for physical model or simulation model of air injection only simply uses different-layer permeability of porous media. In practice, reservoir heterogeneity follows the principle of geostatistics. How much of contrast in permeability actually challenges the air injection in light oil reservoir? This should be investigated by using layered porous medial settings of the classical Dykstra-Parsons style. Unfortunately, there has been no work addressing this issue for air injection in light oil reservoir. In this paper, Reservoir heterogeneity is quantified based on the use of different reservoir permeability distribution according to classical Dykstra-Parsons coefficients method. The aim of this work is to investigate the effect of reservoir heterogeneity on physical process and production performance of air injection in light oil reservoir through numerical reservoir simulation approach. The basic model is calibrated based on previous study. Total eleven pseudo compounders are included in this model and ten complexity of reactions are proposed to achieve the reaction scheme. Results show that oil recovery factor is decreased with the increasing of reservoir heterogeneity both for air and N2 injection from updip location, which is against the working behavior of air injection from updip location. Reservoir heterogeneity sometimes can act as positive effect to improve sweep efficiency as well as enhance production performance for air injection. High O2 content air injection can benefit oil recovery factor, also lead to early O2 breakthrough in heterogeneous reservoir. Well

  18. Characterization of oil and gas reservoir heterogeneity

    Energy Technology Data Exchange (ETDEWEB)

    Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

    1992-10-01

    Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a heterogeneity matrix'' based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

  19. Mathematical simulation of oil reservoir properties

    International Nuclear Information System (INIS)

    Ramirez, A.; Romero, A.; Chavez, F.; Carrillo, F.; Lopez, S.

    2008-01-01

    The study and computational representation of porous media properties are very important for many industries where problems of fluid flow, percolation phenomena and liquid movement and stagnation are involved, for example, in building constructions, ore processing, chemical industries, mining, corrosion sciences, etc. Nevertheless, these kinds of processes present a noneasy behavior to be predicted and mathematical models must include statistical analysis, fractal and/or stochastic procedures to do it. This work shows the characterization of sandstone berea core samples which can be found as a porous media (PM) in natural oil reservoirs, rock formations, etc. and the development of a mathematical algorithm for simulating the anisotropic characteristics of a PM based on a stochastic distribution of some of their most important properties like porosity, permeability, pressure and saturation. Finally a stochastic process is used again to simulated the topography of an oil reservoir

  20. Modeling Permeability Alteration in Diatomite Reservoirs During Steam Drive, SUPRI TR-113

    Energy Technology Data Exchange (ETDEWEB)

    Bhat, Suniti Kumar; Kovscek, Anthony R.

    1999-08-09

    There is an estimated 10 billion barrels of original oil in place (OOIP) in diatomaceous reservoirs in Kern County, California. These reservoirs have low permeability ranging from 0.1 to 10 mD. Injection pressure controlled steam drive has been found to be an effective way to recover oil from these reservoir. However, steam drive in these reservoirs has its own complications. The rock matrix is primarily silica (SiO2). It is a known fact that silica is soluble in hot water and its solubility varies with temperature and pH. Due to this fact, the rock matrix in diatomite may dissolve into the aqueous phase as the temperature at a location increases or it may precipitate from the aqueous phase onto the rock grains as the temperature decreases. Thus, during steam drive silica redistribution will occur in the reservoir along with oil recovery. This silica redistribution causes the permeability and porosity of the reservoir to change. Understanding and quantifying these silica redistribution effects on the reservoir permeability might prove to be a key aspect of designing a steam drive project in these formations.

  1. Forecast on Water Locking Damage of Low Permeable Reservoir with Quantum Neural Network

    Science.gov (United States)

    Zhao, Jingyuan; Sun, Yuxue; Feng, Fuping; Zhao, Fulei; Sui, Dianjie; Xu, Jianjun

    2018-01-01

    It is of great importance in oil-gas reservoir protection to timely and correctly forecast the water locking damage, the greatest damage for low permeable reservoir. An analysis is conducted on the production mechanism and various influence factors of water locking damage, based on which a quantum neuron is constructed based on the information processing manner of a biological neuron and the principle of quantum neural algorithm, besides, the quantum neural network model forecasting the water locking of the reservoir is established and related software is also made to forecast the water locking damage of the gas reservoir. This method has overcome the defects of grey correlation analysis that requires evaluation matrix analysis and complicated operation. According to the practice in Longxi Area of Daqing Oilfield, this method is characterized by fast operation, few system parameters and high accuracy rate (the general incidence rate may reach 90%), which can provide reliable support for the protection technique of low permeable reservoir.

  2. Analytical Estimation of Water-Oil Relative Permeabilities through Fractures

    Directory of Open Access Journals (Sweden)

    Saboorian-Jooybari Hadi

    2016-05-01

    Full Text Available Modeling multiphase flow through fractures is a key issue for understanding flow mechanism and performance prediction of fractured petroleum reservoirs, geothermal reservoirs, underground aquifers and carbon-dioxide sequestration. One of the most challenging subjects in modeling of fractured petroleum reservoirs is quantifying fluids competition for flow in fracture network (relative permeability curves. Unfortunately, there is no standard technique for experimental measurement of relative permeabilities through fractures and the existing methods are very expensive, time consuming and erroneous. Although, several formulations were presented to calculate fracture relative permeability curves in the form of linear and power functions of flowing fluids saturation, it is still unclear what form of relative permeability curves must be used for proper modeling of flow through fractures and consequently accurate reservoir simulation. Basically, the classic linear relative permeability (X-type curves are used in almost all of reservoir simulators. In this work, basic fluid flow equations are combined to develop a new simple analytical model for water-oil two phase flow in a single fracture. The model gives rise to simple analytic formulations for fracture relative permeabilities. The model explicitly proves that water-oil relative permeabilities in fracture network are functions of fluids saturation, viscosity ratio, fluids density, inclination of fracture plane from horizon, pressure gradient along fracture and rock matrix wettability, however they were considered to be only functions of saturations in the classic X-type and power (Corey [35] and Honarpour et al. [28, 29] models. Eventually, validity of the proposed formulations is checked against literature experimental data. The proposed fracture relative permeability functions have several advantages over the existing ones. Firstly, they are explicit functions of the parameters which are known for

  3. Diagenetic effect on permeabilities of geothermal sandstone reservoirs

    DEFF Research Database (Denmark)

    Weibel, Rikke; Olivarius, Mette; Kristensen, Lars

    The Danish subsurface contains abundant sedimentary deposits, which can be utilized for geothermal heating. The Upper Triassic – Lower Jurassic continental-marine sandstones of the Gassum Formation has been utilised as a geothermal reservoir for the Thisted Geothermal Plant since 1984 extracting...... and permeability is caused by increased diagenetic changes of the sandstones due to increased burial depth and temperatures. Therefore, the highest water temperatures typically correspond with the lowest porosities and permeabilities. Especially the permeability is crucial for the performance of the geothermal......-line fractures. Continuous thin chlorite coatings results in less porosity- and permeability-reduction with burial than the general reduction with burial, unless carbonate cemented. Therefore, localities of sandstones characterized by these continuous chlorite coatings may represent fine geothermal reservoirs...

  4. Upscaling verticle permeability within a fluvio-aeolian reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Thomas, S.D.; Corbett, P.W.M.; Jensen, J.L. [Heriot-Watt Univ., Edinburgh (United Kingdom)

    1997-08-01

    Vertical permeability (k{sub v}) is a crucial factor in many reservoir engineering issues. To date there has been little work undertaken to understand the wide variation of k{sub v} values measured at different scales in the reservoir. This paper presents the results of a study in which we have modelled the results of a downhole well tester using a statistical model and high resolution permeability data. The work has demonstrates and quantifies a wide variation in k{sub v} at smaller, near wellbore scales and has implications for k{sub v} modelling at larger scales.

  5. Environmental response nanosilica for reducing the pressure of water injection in ultra-low permeability reservoirs

    Science.gov (United States)

    Liu, Peisong; Niu, Liyong; Li, Xiaohong; Zhang, Zhijun

    2017-12-01

    The super-hydrophobic silica nanoparticles are applied to alter the wettability of rock surface from water-wet to oil-wet. The aim of this is to reduce injection pressure so as to enhance water injection efficiency in low permeability reservoirs. Therefore, a new type of environmentally responsive nanosilica (denote as ERS) is modified with organic compound containing hydrophobic groups and "pinning" groups by covalent bond and then covered with a layer of hydrophilic organic compound by chemical adsorption to achieve excellent water dispersibility. Resultant ERS is homogeneously dispersed in water with a size of about 4-8 nm like a micro-emulsion system and can be easily injected into the macro or nano channels of ultra-low permeability reservoirs. The hydrophobic nanosilica core can be released from the aqueous delivery system owing to its strong dependence on the environmental variation from normal condition to injection wells (such as pH and salinity). Then the exposed silica nanoparticles form a thin layer on the surface of narrow pore throat, leading to the wettability from water-wet to oil-wet. More importantly, the two rock cores with different permeability were surface treated with ERS dispersion with a concentration of 2 g/L, exhibit great reduce of water injection pressure by 57.4 and 39.6%, respectively, which shows great potential for exploitation of crude oil from ultra-low permeability reservoirs during water flooding. [Figure not available: see fulltext.

  6. Prediction of Hydrocarbon Reservoirs Permeability Using Support Vector Machine

    Directory of Open Access Journals (Sweden)

    R. Gholami

    2012-01-01

    Full Text Available Permeability is a key parameter associated with the characterization of any hydrocarbon reservoir. In fact, it is not possible to have accurate solutions to many petroleum engineering problems without having accurate permeability value. The conventional methods for permeability determination are core analysis and well test techniques. These methods are very expensive and time consuming. Therefore, attempts have usually been carried out to use artificial neural network for identification of the relationship between the well log data and core permeability. In this way, recent works on artificial intelligence techniques have led to introduce a robust machine learning methodology called support vector machine. This paper aims to utilize the SVM for predicting the permeability of three gas wells in the Southern Pars field. Obtained results of SVM showed that the correlation coefficient between core and predicted permeability is 0.97 for testing dataset. Comparing the result of SVM with that of a general regression neural network (GRNN revealed that the SVM approach is faster and more accurate than the GRNN in prediction of hydrocarbon reservoirs permeability.

  7. Possibility of predicting the water drive mechanism of oil bearing reservoirs before its exploitation

    Energy Technology Data Exchange (ETDEWEB)

    Cubric, S

    1971-10-01

    The study deals with the application of Van Everdingen and Hurst's method to prediction of water influx from aquifer into an oil-bearing part of a reservoir. The examples show an influence of the factors affecting the water influx (time, permeability, ratio of radii of the aquifer, and oil-bearing part of reservoir.)

  8. Low permeability Neogene lithofacies in Northern Croatia as potential unconventional hydrocarbon reservoirs

    Science.gov (United States)

    Malvić, Tomislav; Sučić, Antonija; Cvetković, Marko; Resanović, Filip; Velić, Josipa

    2014-06-01

    We present two examples of describing low permeability Neogene clastic lithofacies to outline unconventional hydrocarbon lithofacies. Both examples were selected from the Drava Depression, the largest macrostructure of the Pannonian Basin System located in Croatia. The first example is the Beničanci Field, the largest Croatian hydrocarbon reservoir discovered in Badenian coarse-grained clastics that consists mostly of breccia. The definition of low permeability lithofacies is related to the margins of the existing reservoir, where the reservoir lithology changed into a transitional one, which is mainly depicted by the marlitic sandstones. However, calculation of the POS (probability of success of new hydrocarbons) shows critical geological categories where probabilities are lower than those in the viable reservoir with proven reserves. Potential new hydrocarbon volumes are located in the structural margins, along the oil-water contact, with a POS of 9.375%. These potential reserves in those areas can be classified as probable. A second example was the Cremušina Structure, where a hydrocarbon reservoir was not proven, but where the entire structure has been transferred onto regional migration pathways. The Lower Pontian lithology is described from well logs as fine-grained sandstones with large sections of silty or marly clastics. As a result, the average porosity is low for conventional reservoir classification (10.57%). However, it is still an interesting case for consideration as a potentially unconventional reservoir, such as the "tight" sandstones.

  9. Thermoporoelastic effects during heat extraction from low-permeability reservoirs

    DEFF Research Database (Denmark)

    Salimzadeh, Saeed; Nick, Hamidreza M.; Zimmerman, R. W.

    2018-01-01

    Thermoporoelastic effects during heat extraction from low permeability geothermal reservoirs are investigated numerically, based on the model of a horizontal penny-shaped fracture intersected by an injection well and a production well. A coupled formulation for thermo-hydraulic (TH) processes...... in EGS projects. Therefore, using the undrained thermal expansion coefficient for the matrix may overestimate the volumetric strain of the rock in low-permeability enhanced geothermal systems, whereas using a drained thermal expansion coefficient for the matrix may underestimate the volumetric strain...

  10. New well pattern optimization methodology in mature low-permeability anisotropic reservoirs

    Science.gov (United States)

    Qin, Jiazheng; Liu, Yuetian; Feng, Yueli; Ding, Yao; Liu, Liu; He, Youwei

    2018-02-01

    In China, lots of well patterns were designed before people knew the principal permeability direction in low-permeability anisotropic reservoirs. After several years’ production, it turns out that well line direction is unparallel with principal permeability direction. However, traditional well location optimization methods (in terms of the objective function such as net present value and/or ultimate recovery) are inapplicable, since wells are not free to move around in a mature oilfield. Thus, the well pattern optimization (WPO) of mature low-permeability anisotropic reservoirs is a significant but challenging task, since the original well pattern (WP) will be distorted and reconstructed due to permeability anisotropy. In this paper, we investigate the destruction and reconstruction of WP when the principal permeability direction and well line direction are unparallel. A new methodology was developed to quantitatively optimize the well locations of mature large-scale WP through a WPO algorithm on the basis of coordinate transformation (i.e. rotating and stretching). For a mature oilfield, large-scale WP has settled, so it is not economically viable to carry out further infill drilling. This paper circumvents this difficulty by combining the WPO algorithm with the well status (open or shut-in) and schedule adjustment. Finally, this methodology is applied to an example. Cumulative oil production rates of the optimized WP are higher, and water-cut is lower, which highlights the potential of the WPO methodology application in mature large-scale field development projects.

  11. Visualization of viscous coupling effects in heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Ortiz-Arango, J.D. [Calgary Univ., AB (Canada). Tomographic Imaging and Porous Media Laboratory; Kantzas, A. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[Calgary Univ., AB (Canada). Tomographic Imaging and Porous Media Laboratory

    2008-10-15

    Some heavy oil reservoirs in Venezuela and Canada have shown higher than expected production rates attributed to the effects of foamy oil or enhanced solution gas drive. However, foamy oil 2-phase flow does not fully explain oil rate enhancement in heavy oil reservoirs. In this study, flow visualization experiments were conducted in a 2-D etched network micromodel in order to determine the effect of the viscosity ratio on oil mobility at the pore scale. The micromodel's pattern was characterized by macroscopic heterogeneities with a random network of larger pore bodies interconnected with a random network of smaller pore throats. Displacement tests were conducted with green-dyed distilled water as a wetting phase. N-octane, bromododecane and mineral oil were used as non-wetting phases. An unsteady-state method was used to obtain displacement data, and the Alternate method was used to calculate relative permeabilities. Results of the study showed that relative permeabilities depended on the viscosity ratio of the fluids flowing through the porous medium. Channel and annular flows co-existed, and water lubrication was stronger at higher water saturations. The results of the study explained the abnormally high production rates in heavier oil fields. 19 refs., 3 tabs., 14 figs.

  12. An improved method for permeability estimation of the bioclastic limestone reservoir based on NMR data.

    Science.gov (United States)

    Ge, Xinmin; Fan, Yiren; Liu, Jianyu; Zhang, Li; Han, Yujiao; Xing, Donghui

    2017-10-01

    Permeability is an important parameter in formation evaluation since it controls the fluid transportation of porous rocks. However, it is challengeable to compute the permeability of bioclastic limestone reservoirs by conventional methods linking petrophysical and geophysical data, due to the complex pore distributions. A new method is presented to estimate the permeability based on laboratory and downhole nuclear magnetic resonance (NMR) measurements. We divide the pore space into four intervals by the inflection points between the pore radius and the transversal relaxation time. Relationships between permeability and percentages of different pore intervals are investigated to investigate influential factors on the fluid transportation. Furthermore, an empirical model, which takes into account of the pore size distributions, is presented to compute the permeability. 212 core samples in our case show that the accuracy of permeability calculation is improved from 0.542 (SDR model), 0.507 (TIM model), 0.455 (conventional porosity-permeability regressions) to 0.803. To enhance the precision of downhole application of the new model, we developed a fluid correction algorithm to construct the water spectrum of in-situ NMR data, aiming to eliminate the influence of oil on the magnetization. The result reveals that permeability is positively correlated with percentages of mega-pores and macro-pores, but negatively correlated with the percentage of micro-pores. Poor correlation is observed between permeability and the percentage of meso-pores. NMR magnetizations and T 2 spectrums after the fluid correction agree well with laboratory results for samples saturated with water. Field application indicates that the improved method provides better performance than conventional models such as Schlumberger-Doll Research equation, Timur-Coates equation, and porosity-permeability regressions. Copyright © 2017 Elsevier Inc. All rights reserved.

  13. An improved method for permeability estimation of the bioclastic limestone reservoir based on NMR data

    Science.gov (United States)

    Ge, Xinmin; Fan, Yiren; Liu, Jianyu; Zhang, Li; Han, Yujiao; Xing, Donghui

    2017-10-01

    Permeability is an important parameter in formation evaluation since it controls the fluid transportation of porous rocks. However, it is challengeable to compute the permeability of bioclastic limestone reservoirs by conventional methods linking petrophysical and geophysical data, due to the complex pore distributions. A new method is presented to estimate the permeability based on laboratory and downhole nuclear magnetic resonance (NMR) measurements. We divide the pore space into four intervals by the inflection points between the pore radius and the transversal relaxation time. Relationships between permeability and percentages of different pore intervals are investigated to investigate influential factors on the fluid transportation. Furthermore, an empirical model, which takes into account of the pore size distributions, is presented to compute the permeability. 212 core samples in our case show that the accuracy of permeability calculation is improved from 0.542 (SDR model), 0.507 (TIM model), 0.455 (conventional porosity-permeability regressions) to 0.803. To enhance the precision of downhole application of the new model, we developed a fluid correction algorithm to construct the water spectrum of in-situ NMR data, aiming to eliminate the influence of oil on the magnetization. The result reveals that permeability is positively correlated with percentages of mega-pores and macro-pores, but negatively correlated with the percentage of micro-pores. Poor correlation is observed between permeability and the percentage of meso-pores. NMR magnetizations and T2 spectrums after the fluid correction agree well with laboratory results for samples saturated with water. Field application indicates that the improved method provides better performance than conventional models such as Schlumberger-Doll Research equation, Timur-Coates equation, and porosity-permeability regressions.

  14. Characterization of oil and gas reservoir heterogeneity. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

    1992-10-01

    Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a ``heterogeneity matrix`` based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

  15. Estimation of Oil Production Rates in Reservoirs Exposed to Focused Vibrational Energy

    KAUST Repository

    Jeong, Chanseok

    2014-01-01

    Elastic wave-based enhanced oil recovery (EOR) is being investigated as a possible EOR method, since strong wave motions within an oil reservoir - induced by earthquakes or artificially generated vibrations - have been reported to improve the production rate of remaining oil from existing oil fields. To date, there are few theoretical studies on estimating how much bypassed oil within an oil reservoir could be mobilized by such vibrational stimulation. To fill this gap, this paper presents a numerical method to estimate the extent to which the bypassed oil is mobilized from low to high permeability reservoir areas, within a heterogeneous reservoir, via wave-induced cross-flow oscillation at the interface between the two reservoir permeability areas. This work uses the finite element method to numerically obtain the pore fluid wave motion within a one-dimensional fluid-saturated porous permeable elastic solid medium embedded in a non-permeable elastic semi-infinite solid. To estimate the net volume of mobilized oil from the low to the high permeability area, a fluid flow hysteresis hypothesis is adopted to describe the behavior at the interface between the two areas. Accordingly, the fluid that is moving from the low to the high permeability areas is assumed to transport a larger volume of oil than the fluid moving in the opposite direction. The numerical experiments were conducted by using a prototype heterogeneous oil reservoir model, subjected to ground surface dynamic loading operating at low frequencies (1 to 50 Hz). The numerical results show that a sizeable amount of oil could be mobilized via the elastic wave stimulation. It is observed that certain wave frequencies are more effective than others in mobilizing the remaining oil. We remark that these amplification frequencies depend on the formation’s elastic properties. This numerical work shows that the wave-based mobilization of the bypassed oil in a heterogeneous oil reservoir is feasible, especially

  16. Effect of lithological composition of oil reservoirs on oil production by a hot agent

    Energy Technology Data Exchange (ETDEWEB)

    Abbasov, A A; Kasimov, Sh A

    1965-01-01

    Several small-scale experiments were performed to determine the effect of steam on oil recovery and on permeability of water-sensitive clay-containing cores. Steam has 2 contradictory actions on oil recovery - (1) steam increases temperature and decreases viscosity of the oil, which aids oil recovery; and (2) steam hydrates and swells clays, which reduces permeability and hinders oil recovery. The oil-recovery experiments were carried out with consolidated cores containing 0, 10, and 22% clay, saturated with water and 28 cp crude oil; superheated steam at 125-300$C was used. The following conclusions were made from the experimental results: (1) oil recovery decreased as clay content of cores increased; however, at all temperatures steam recovered more oil than cold water did. (2) As steam temperature increases, oil recovery reaches a maximum, then decreases. The temperature at which oil recovery begins to decrease depends on core clay content; the higher the clay content, the lower this temperature. (3) Irrespective of whether a reservoir contains clay or not, oil recovery is considerably greater with steam than with water.

  17. SIMULATION AND OPTIMIZATION OF THE HYDRAULIC FRACTURING OPERATION IN A HEAVY OIL RESERVOIR IN SOUTHERN IRAN

    Directory of Open Access Journals (Sweden)

    REZA MASOOMI

    2017-01-01

    Full Text Available Extraction of oil from some Iranian reservoirs due to high viscosity of their oil or reducing the formation permeability due to asphaltene precipitation or other problems is not satisfactory. Hydraulic fracturing method increases production in the viscous oil reservoirs that the production rate is low. So this is very important for some Iranian reservoirs that contain these characteristics. In this study, hydraulic fracturing method has been compositionally simulated in a heavy oil reservoir in southern Iran. In this study, the parameters of the fracture half length, the propagation direction of the cracks and the depth of fracturing have been considered in this oil reservoir. The aim of this study is to find the best scenario which has the highest recovery factor in this oil reservoir. For this purpose the parameters of the length, propagation direction and depth of fracturing have been optimized in this reservoir. Through this study the cumulative oil production has been evaluated with the compositional simulation for the next 10 years in this reservoir. Also at the end of this paper, increasing the final production of this oil reservoir caused by optimized hydraulic fracturing has been evaluated.

  18. The Role of Horizontal Wells when Developing Low-Permeable, Heterogeneous Reservoirs

    Directory of Open Access Journals (Sweden)

    M.P. Yurova

    2017-09-01

    Full Text Available The widespread use of horizontal drilling in recent years has shown that horizontal wells can be successfully used both at the initial and late stages of development. This is due to the fact that horizontal wells, in contrast to vertical wells, contact a larger area of ​​the productive formation, while the surface of drainage of the oil-saturated layer, productivity of the wells due to the formation of cracks, and also the influence on thin layers increases. One of the methods of impact on the reservoir is the steam-thermal method. The main advantage of the use of the heat wave method in horizontal wells is a significant increase in the well production rate, a decrease in the water cut of the reservoir, a decrease in the oil viscosity, an increase in the injectivity of the injection well, and an increase in the inflow in producing wells. As a result of the total effect, a significant increase in production is obtained throughout the entire deposit. Enhanced oil recovery from the injection of steam is achieved by reducing the viscosity of oil, covering the reservoir with steam, distilling oil and extracting with a solvent. All this increases the displacement coefficient. One of the most effective ways to increase oil recovery at a late stage of field operation is sidetracking in emergency, highly watered and low-productive wells. This leads to the development of residual reserves in weakly drained zones of reservoirs with a substantial increase in well productivity in low-permeable reservoirs. This approach assumes that the initial drilling of wells is a ‘pilot’ stage, which precedes the development of oil reserves in the late stages of deposit development. In the fields of Western Siberia, multiple hydraulic fracturing of the reservoir has been improved due to a special stinger in the liner hanger of multi-packer installation, which excludes the influence of high pressures on the production column under the multiple hydraulic fracturing

  19. Microbial Enhanced Oil Recovery - Advanced Reservoir Simulation

    DEFF Research Database (Denmark)

    Nielsen, Sidsel Marie

    the water phase. The biofilm formation implies that the concentration of bacteria near the inlet increases. In combination with surfactant production, the biofilm results in a higher surfactant concentration in the initial part of the reservoir. The oil that is initially bypassed in connection...... simulator. In the streamline simulator, the effect of gravity is introduced using an operator splitting technique. The gravity effect stabilizes oil displacement causing markedly improvement of the oil recovery, when the oil density becomes relatively low. The general characteristics found for MEOR in one......-dimensional simulations are also demonstrated both in two and three dimensions. Overall, this MEOR process conducted in a heterogeneous reservoir also produces more oil compared to waterflooding, when the simulations are run in multiple dimensions. The work presented in this thesis has resulted in two publications so far....

  20. Refined reservoir description to maximize oil recovery

    International Nuclear Information System (INIS)

    Flewitt, W.E.

    1975-01-01

    To assure maximized oil recovery from older pools, reservoir description has been advanced by fully integrating original open-hole logs and the recently introduced interpretive techniques made available through cased-hole wireline saturation logs. A refined reservoir description utilizing normalized original wireline porosity logs has been completed in the Judy Creek Beaverhill Lake ''A'' Pool, a reefal carbonate pool with current potential productivity of 100,000 BOPD and 188 active wells. Continuous porosity was documented within a reef rim and cap while discontinuous porous lenses characterized an interior lagoon. With the use of pulsed neutron logs and production data a separate water front and pressure response was recognized within discrete environmental units. The refined reservoir description aided in reservoir simulation model studies and quantifying pool performance. A pattern water flood has now replaced the original peripheral bottom water drive to maximize oil recovery

  1. Oil Reservoir Production Optimization using Optimal Control

    DEFF Research Database (Denmark)

    Völcker, Carsten; Jørgensen, John Bagterp; Stenby, Erling Halfdan

    2011-01-01

    Practical oil reservoir management involves solution of large-scale constrained optimal control problems. In this paper we present a numerical method for solution of large-scale constrained optimal control problems. The method is a single-shooting method that computes the gradients using the adjo...... reservoir using water ooding and smart well technology. Compared to the uncontrolled case, the optimal operation increases the Net Present Value of the oil field by 10%.......Practical oil reservoir management involves solution of large-scale constrained optimal control problems. In this paper we present a numerical method for solution of large-scale constrained optimal control problems. The method is a single-shooting method that computes the gradients using...

  2. Improving reservoir history matching of EM heated heavy oil reservoirs via cross-well seismic tomography

    KAUST Repository

    Katterbauer, Klemens; Hoteit, Ibrahim

    2014-01-01

    process. While becoming a promising technology for heavy oil recovery, its effect on overall reservoir production and fluid displacements are poorly understood. Reservoir history matching has become a vital tool for the oil & gas industry to increase

  3. Permeability estimation from NMR diffusion measurements in reservoir rocks.

    Science.gov (United States)

    Balzarini, M; Brancolini, A; Gossenberg, P

    1998-01-01

    It is well known that in restricted geometries, such as in porous media, the apparent diffusion coefficient (D) of the fluid depends on the observation time. From the time dependence of D, interesting information can be derived to characterise geometrical features of the porous media that are relevant in oil industry applications. In particular, the permeability can be related to the surface-to-volume ratio (S/V), estimated from the short time behaviour of D(t), and to the connectivity of the pore space, which is probed by the long time behaviour of D(t). The stimulated spin-echo pulse sequence, with pulsed magnetic field gradients, has been used to measure the diffusion coefficients on various homogeneous and heterogeneous sandstone samples. It is shown that the petrophysical parameters obtained by our measurements are in good agreement with those yielded by conventional laboratory techniques (gas permeability and electrical conductivity). Although the diffusing time is limited by T1, eventually preventing an observation of the real asymptotic behaviour, and the surface-to-volume ratio measured by nuclear magnetic resonance is different from the value obtained by BET because of the different length scales probed, the measurement remains reliable and low-time consuming.

  4. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Reid B. Grigg

    2003-10-31

    The second annual report of ''Improving CO{sub 2} Efficiency for Recovery Oil in Heterogeneous Reservoirs'' presents results of laboratory studies with related analytical models for improved oil recovery. All studies have been undertaken with the intention to optimize utilization and extend the practice of CO{sub 2} flooding to a wider range of reservoirs. Many items presented in this report are applicable to other interest areas: e.g. gas injection and production, greenhouse gas sequestration, chemical flooding, reservoir damage, etc. Major areas of studies include reduction of CO{sub 2} mobility to improve conformance, determining and understanding injectivity changes in particular injectivity loses, and modeling process mechanisms determined in the first two areas. Interfacial tension (IFT) between a high-pressure, high-temperature CO{sub 2} and brine/surfactant and foam stability are used to assess and screen surfactant systems. In this work the effects of salinity, pressure, temperature, surfactant concentration, and the presence of oil on IFT and CO{sub 2} foam stability were determined on the surfactant (CD1045{trademark}). Temperature, pressure, and surfactant concentration effected both IFT and foam stability while oil destabilized the foam, but did not destroy it. Calcium lignosulfonate (CLS) can be used as a sacrificial and an enhancing agent. This work indicates that on Berea sandstone CLS concentration, brine salinity, and temperature are dominant affects on both adsorption and desorption and that adsorption is not totally reversible. Additionally, CLS adsorption was tested on five minerals common to oil reservoirs; it was found that CLS concentration, salinity, temperature, and mineral type had significant effects on adsorption. The adsorption density from most to least was: bentonite > kaolinite > dolomite > calcite > silica. This work demonstrates the extent of dissolution and precipitation from co-injection of CO{sub 2} and

  5. Characterization of oil and gas reservoir heterogeneity

    Energy Technology Data Exchange (ETDEWEB)

    1991-01-01

    The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

  6. On the evaluation of steam assisted gravity drainage in naturally fractured oil reservoirs

    Directory of Open Access Journals (Sweden)

    Seyed Morteza Tohidi Hosseini

    2017-06-01

    Full Text Available Steam Assisted Gravity Drainage (SAGD as a successful enhanced oil recovery (EOR process has been applied to extract heavy and extra heavy oils. Huge amount of global heavy oil resources exists in carbonate reservoirs which are mostly naturally fractured reservoirs. Unlike clastic reservoirs, few studies were carried out to determine the performance of SAGD in carbonate reservoirs. Even though SAGD is a highly promising technique, several uncertainties and unanswered questions still exist and they should be clarified for expansion of SAGD methods to world wide applications especially in naturally fractured reservoirs. In this communication, the effects of some operational and reservoir parameters on SAGD processes were investigated in a naturally fractured reservoir with oil wet rock using CMG-STARS thermal simulator. The purpose of this study was to investigate the role of fracture properties including fracture orientation, fracture spacing and fracture permeability on the SAGD performance in naturally fractured reservoirs. Moreover, one operational parameter was also studied; one new well configuration, staggered well pair was evaluated. Results indicated that fracture orientation influences steam expansion and oil production from the horizontal well pairs. It was also found that horizontal fractures have unfavorable effects on oil production, while vertical fractures increase the production rate for the horizontal well. Moreover, an increase in fracture spacing results in more oil production, because in higher fracture spacing model, steam will have more time to diffuse into matrices and heat up the entire reservoir. Furthermore, an increase in fracture permeability results in process enhancement and ultimate recovery improvement. Besides, diagonal change in the location of injection wells (staggered model increases the recovery efficiency in long-term production plan.

  7. Two-phase flow in volatile oil reservoir using two-phase pseudo-pressure well test method

    Energy Technology Data Exchange (ETDEWEB)

    Sharifi, M.; Ahmadi, M. [Calgary Univ., AB (Canada)

    2009-09-15

    A study was conducted to better understand the behaviour of volatile oil reservoirs. Retrograde condensation occurs in gas-condensate reservoirs when the flowing bottomhole pressure (BHP) lowers below the dewpoint pressure, thus creating 4 regions in the reservoir with different liquid saturations. Similarly, when the BHP of volatile oil reservoirs falls below the bubblepoint pressure, two phases are created in the region around the wellbore, and a single phase (oil) appears in regions away from the well. In turn, higher gas saturation causes the oil relative permeability to decrease towards the near-wellbore region. Reservoir compositional simulations were used in this study to predict the fluid behaviour below the bubblepoint. The flowing bottomhole pressure was then exported to a well test package to diagnose the occurrence of different mobility regions. The study also investigated the use of a two-phase pseudo-pressure method on volatile and highly volatile oil reservoirs. It was concluded that this method can successfully predict the true permeability and mechanical skin. It can also distinguish between mechanical skin and condensate bank skin. As such, the two-phase pseudo-pressure method is particularly useful for developing after-drilling well treatment and enhanced oil recovery process designs. However, accurate relative permeability and PVT data must be available for reliable interpretation of the well test in volatile oil reservoirs. 18 refs., 3 tabs., 9 figs.

  8. Nuclear stimulation of oil-reservoirs

    International Nuclear Information System (INIS)

    Delort, F.; Supiot, F.

    1970-01-01

    Underground nuclear explosions in the Hoggar nuclear test site have shown that the geological effects may increase the production of oil or gas reservoirs. By studying the permanent liquid flow-rate with approximate DUPUIT's equation, or with a computer code, it is shown that the conventional well flow-rate may be increased by a factor between 3 and 50, depending on the medium and explosion conditions. (author)

  9. Nuclear stimulation of oil-reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Delort, F; Supiot, F [Commissariat a l' Energie Atomique, Centre d' Etudes de Bruyere-le-Chatel (France)

    1970-05-01

    Underground nuclear explosions in the Hoggar nuclear test site have shown that the geological effects may increase the production of oil or gas reservoirs. By studying the permanent liquid flow-rate with approximate DUPUIT's equation, or with a computer code, it is shown that the conventional well flow-rate may be increased by a factor between 3 and 50, depending on the medium and explosion conditions. (author)

  10. Local Refinement of the Super Element Model of Oil Reservoir

    Directory of Open Access Journals (Sweden)

    A.B. Mazo

    2017-12-01

    Full Text Available In this paper, we propose a two-stage method for petroleum reservoir simulation. The method uses two models with different degrees of detailing to describe hydrodynamic processes of different space-time scales. At the first stage, the global dynamics of the energy state of the deposit and reserves is modeled (characteristic scale of such changes is km / year. The two-phase flow equations in the model of global dynamics operate with smooth averaged pressure and saturation fields, and they are solved numerically on a large computational grid of super-elements with a characteristic cell size of 200-500 m. The tensor coefficients of the super-element model are calculated using special procedures of upscaling of absolute and relative phase permeabilities. At the second stage, a local refinement of the super-element model is constructed for calculating small-scale processes (with a scale of m / day, which take place, for example, during various geological and technical measures aimed at increasing the oil recovery of a reservoir. Then we solve the two-phase flow problem in the selected area of the measure exposure on a detailed three-dimensional grid, which resolves the geological structure of the reservoir, and with a time step sufficient for describing fast-flowing processes. The initial and boundary conditions of the local problem are formulated on the basis of the super-element solution. This approach allows us to reduce the computational costs in order to solve the problems of designing and monitoring the oil reservoir. To demonstrate the proposed approach, we give an example of the two-stage modeling of the development of a layered reservoir with a local refinement of the model during the isolation of a water-saturated high-permeability interlayer. We show a good compliance between the locally refined solution of the super-element model in the area of measure exposure and the results of numerical modeling of the whole history of reservoir

  11. The Researches on Reasonable Well Spacing of Gas Wells in Deep and low Permeability Gas Reservoirs

    Science.gov (United States)

    Bei, Yu Bei; Hui, Li; Lin, Li Dong

    2018-06-01

    This Gs64 gas reservoir is a condensate gas reservoir which is relatively integrated with low porosity and low permeability found in Dagang Oilfield in recent years. The condensate content is as high as 610g/m3. At present, there are few reports about the well spacing of similar gas reservoirs at home and abroad. Therefore, determining the reasonable well spacing of the gas reservoir is important for ensuring the optimal development effect and economic benefit of the gas field development. This paper discusses the reasonable well spacing of the deep and low permeability gas reservoir from the aspects of percolation mechanics, gas reservoir engineering and numerical simulation. considering there exist the start-up pressure gradient in percolation process of low permeability gas reservoir, this paper combined with productivity equation under starting pressure gradient, established the formula of gas well spacing with the formation pressure and start-up pressure gradient. The calculation formula of starting pressure gradient and well spacing of gas wells. Adopting various methods to calculate values of gas reservoir spacing are close to well testing' radius, so the calculation method is reliable, which is very important for the determination of reasonable well spacing in low permeability gas reservoirs.

  12. Research on oil recovery mechanisms in heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Kovscek, Anthony R.; Brigham, William E., Castanier, Louis M.

    2000-03-16

    The research described here was directed toward improved understanding of thermal and heavy-oil production mechanisms and is categorized into: (1) flow and rock properties, (2) in-situ combustion, (3) additives to improve mobility control, (4) reservoir definition, and (5) support services. The scope of activities extended over a three-year period. Significant work was accomplished in the area of flow properties of steam, water, and oil in consolidated and unconsolidated porous media, transport in fractured porous media, foam generation and flow in homogeneous and heterogeneous porous media, the effects of displacement pattern geometry and mobility ratio on oil recovery, and analytical representation of water influx.

  13. RESEARCH OIL RECOVERY MECHANISMS IN HEAVY OIL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Anthony R. Kovscek; William E. Brigham

    1999-06-01

    The United States continues to rely heavily on petroleum fossil fuels as a primary energy source, while domestic reserves dwindle. However, so-called heavy oil (10 to 20{sup o}API) remains an underutilized resource of tremendous potential. Heavy oils are much more viscous than conventional oils. As a result, they are difficult to produce with conventional recovery methods such as pressure depletion and water injection. Thermal recovery is especially important for this class of reservoirs because adding heat, usually via steam injection, generally reduces oil viscosity dramatically. This improves displacement efficiency. The research described here was directed toward improved understanding of thermal and heavy-oil production mechanisms and is categorized into: (1) flow and rock properties; (2) in-situ combustion; (3) additives to improve mobility control; (4) reservoir definition; and (5) support services. The scope of activities extended over a three-year period. Significant work was accomplished in the area of flow properties of steam, water, and oil in consolidated and unconsolidated porous media, transport in fractured porous media, foam generation and flow in homogeneous and heterogeneous porous media, the effects of displacement pattern geometry and mobility ratio on oil recovery, and analytical representation of water influx. Significant results are described.

  14. Xenon NMR measurements of permeability and tortuosity in reservoir rocks.

    Science.gov (United States)

    Wang, Ruopeng; Pavlin, Tina; Rosen, Matthew Scott; Mair, Ross William; Cory, David G; Walsworth, Ronald Lee

    2005-02-01

    In this work we present measurements of permeability, effective porosity and tortuosity on a variety of rock samples using NMR/MRI of thermal and laser-polarized gas. Permeability and effective porosity are measured simultaneously using MRI to monitor the inflow of laser-polarized xenon into the rock core. Tortuosity is determined from measurements of the time-dependent diffusion coefficient using thermal xenon in sealed samples. The initial results from a limited number of rocks indicate inverse correlations between tortuosity and both effective porosity and permeability. Further studies to widen the number of types of rocks studied may eventually aid in explaining the poorly understood connection between permeability and tortuosity of rock cores.

  15. Effect of stratification on segregation in carbon dioxide miscible flooding in a water-flooded oil reservoir

    International Nuclear Information System (INIS)

    Bhatti, A.A.; Mahmood, S.M.; Amjad, B.

    2013-01-01

    Oil reservoirs are subjected to tertiary recovery by deploying any enhanced oil recovery (EOR) technique for the recovery of left over oil. Amongst many EOR methods one of the widely applied worldwide is CO/sub 2/ flooding through miscible, near miscible or immiscible displacement processes. CO/sub 2/ flooding process responds to a number of reservoir and fluid characteristics. These characteristics have strong effect on overall efficiency of the displacement process. Better understanding of the effect of different characteristics on displacement process is important to plan an efficient displacement process. In this work, the effect of stratification resulting in gravity segregation of the injected fluid is studied in an oil reservoir which is water-flooded during secondary phase of recovery. Sensitivity analysis is performed through successive simulation on Eclipse 300 (compositional) reservoir simulator. Process involves the continuous CO/sub 2/ injection in an oil reservoir with more than 1/3rd of original oil in place left after water flooding. Reservoir model with four different permeability layers is studied. Four patterns by changing the arrangement of the permeabilities of the layers are analysed. The effect of different arrangement or stratification on segregation of CO/sub 2/ and ultimately on the incremental oil recovery, is investigated. It has been observed that out of four arrangements, upward fining pattern relatively overcame the issue of the segregation of CO/sub 2/ and consequently 33% more oil with half injection volume is recovered when compared with the downward fining pattern. (author)

  16. Bioemulsan Production by Iranian Oil Reservoirs Microorganisms

    Directory of Open Access Journals (Sweden)

    A Amiriyan, M Mazaheri Assadi, VA Saggadian, A Noohi

    2004-10-01

    Full Text Available The biosurfactants are believed to be surface active components that are shed into the surrounding medium during the growth of the microorganisms. The oil degrading microorganism Acinetobacter calcoaceticus RAG-1 produces a poly-anionic biosurfactant, hetero-polysaccharide bioemulsifier termed as emulsan which forms and stabilizes oil-water emulsions with a variety of hydrophobic substrates. In the present paper results of the possibility of biosurfactant (Emulsan production by microorganisms isolated from Iranian oil reservoirs is presented. Fourthy three gram negative and gram positive, non fermentative, rod bacilli and coccobacilli shaped baceria were isolated from the oil wells of Bibi Hakimeh, Siri, Maroon, Ilam , East Paydar and West Paydar. Out of the isolated strains, 39 bacterial strains showed beta haemolytic activity, further screening revealed the emulsifying activity and surface tension. 11 out of 43 tested emulsifiers were identified as possible biosurfactant producers and two isolates produced large surface tension reduction, indicating the high probability of biosurfactant production. Further investigation revealed that, two gram negative, oxidase negative, aerobic and coccoid rods isolates were the best producers and hence designated as IL-1, PAY-4. Whole culture broth of isolates reduced surface tension from 68 mN /m to 30 and 29.1mN/m, respectively, and were stable during exposure to high salinity (10%NaCl and elevated temperatures(120C for 15 min .

  17. Integrated petrophysical and reservoir characterization workflow to enhance permeability and water saturation prediction

    Science.gov (United States)

    Al-Amri, Meshal; Mahmoud, Mohamed; Elkatatny, Salaheldin; Al-Yousef, Hasan; Al-Ghamdi, Tariq

    2017-07-01

    Accurate estimation of permeability is essential in reservoir characterization and in determining fluid flow in porous media which greatly assists optimize the production of a field. Some of the permeability prediction techniques such as Porosity-Permeability transforms and recently artificial intelligence and neural networks are encouraging but still show moderate to good match to core data. This could be due to limitation to homogenous media while the knowledge about geology and heterogeneity is indirectly related or absent. The use of geological information from core description as in Lithofacies which includes digenetic information show a link to permeability when categorized into rock types exposed to similar depositional environment. The objective of this paper is to develop a robust combined workflow integrating geology and petrophysics and wireline logs in an extremely heterogeneous carbonate reservoir to accurately predict permeability. Permeability prediction is carried out using pattern recognition algorithm called multi-resolution graph-based clustering (MRGC). We will bench mark the prediction results with hard data from core and well test analysis. As a result, we showed how much better improvements are achieved in the permeability prediction when geology is integrated within the analysis. Finally, we use the predicted permeability as an input parameter in J-function and correct for uncertainties in saturation calculation produced by wireline logs using the classical Archie equation. Eventually, high level of confidence in hydrocarbon volumes estimation is reached when robust permeability and saturation height functions are estimated in presence of important geological details that are petrophysically meaningful.

  18. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Reid B. Grigg; Robert K. Svec; Zhengwen Zeng; Baojun Bai; Yi Liu

    2004-09-27

    The third annual report of ''Improving CO{sub 2} Efficiency for Recovery Oil in Heterogeneous Reservoirs'' presents results of laboratory studies with related analytical models for improved oil recovery. All studies were designed to optimize utilization and extend the practice of CO{sub 2} flooding to a wider range of reservoirs. Chapter 1 describes the behavior at low concentrations of the surfactant Chaser International CD1045{trademark} (CD) versus different salinity, pressure and temperature. Results of studies on the effects of pH and polymer (hydrolyzed polyacrylamide?HPAM) and CO{sub 2} foam stability after adsorption in the core are also reported. Calcium lignosulfonate (CLS) transport mechanisms through sandstone, description of the adsorption of CD and CD/CLS onto three porous media (sandstone, limestone and dolomite) and five minerals, and the effect of adsorption on foam stability are also reported. In Chapter 2, the adsorption kinetics of CLS in porous Berea sandstone and non-porous minerals are compared by monitoring adsorption density change with time. Results show that adsorption requires a much longer time for the porous versus non-porous medium. CLS adsorption onto sandstone can be divided into three regions: adsorption controlled by dispersion, adsorption controlled by diffusion and adsorption equilibrium. NaI tracer used to characterize the sandstone had similar trends to earlier results for the CLS desorption process, suggesting a dual porosity model to simulate flow through Berea sandstone. The kinetics and equilibrium test for CD adsorption onto five non-porous minerals and three porous media are reported in Chapter 3. CD adsorption and desorption onto non-porous minerals can be established in less than one hour with adsorption densities ranging from 0.4 to 1.2 mg of CD per g of mineral in decreasing order of montmorillonite, dolomite, kaolinite, silica and calcite. The surfactant adsorption onto three porous media takes

  19. Digital Rock Physics Aplications: Visualisation Complex Pore and Porosity-Permeability Estimations of the Porous Sandstone Reservoir

    Science.gov (United States)

    Handoyo; Fatkhan; Del, Fourier

    2018-03-01

    Reservoir rock containing oil and gas generally has high porosity and permeability. High porosity is expected to accommodate hydrocarbon fluid in large quantities and high permeability is associated with the rock’s ability to let hydrocarbon fluid flow optimally. Porosity and permeability measurement of a rock sample is usually performed in the laboratory. We estimate the porosity and permeability of sandstones digitally by using digital images from μCT-Scan. Advantages of the method are non-destructive and can be applied for small rock pieces also easily to construct the model. The porosity values are calculated by comparing the digital image of the pore volume to the total volume of the sandstones; while the permeability values are calculated using the Lattice Boltzmann calculations utilizing the nature of the law of conservation of mass and conservation of momentum of a particle. To determine variations of the porosity and permeability, the main sandstone samples with a dimension of 300 × 300 × 300 pixels are made into eight sub-cubes with a size of 150 × 150 × 150 pixels. Results of digital image modeling fluid flow velocity are visualized as normal velocity (streamline). Variations in value sandstone porosity vary between 0.30 to 0.38 and permeability variations in the range of 4000 mD to 6200 mD. The results of calculations show that the sandstone sample in this research is highly porous and permeable. The method combined with rock physics can be powerful tools for determining rock properties from small rock fragments.

  20. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    Energy Technology Data Exchange (ETDEWEB)

    Unknown

    2001-08-08

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California, through the testing and application of advanced reservoir characterization and thermal production technologies. The hope is that successful application of these technologies will result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs, including: (1) Development of three-dimensional (3-D) deterministic and stochastic reservoir simulation models--thermal or otherwise--to aid in reservoir management of the steamflood and post-steamflood phases and subsequent development work. (2) Development of computerized 3-D visualizations of the geologic and reservoir simulation models to aid reservoir surveillance and operations. (3) Perform detailed studies of the geochemical interactions between the steam and the formation rock and fluids. (4) Testing and proposed application of a

  1. Improving reservoir history matching of EM heated heavy oil reservoirs via cross-well seismic tomography

    KAUST Repository

    Katterbauer, Klemens

    2014-01-01

    Enhanced recovery methods have become significant in the industry\\'s drive to increase recovery rates from oil and gas reservoirs. For heavy oil reservoirs, the immobility of the oil at reservoir temperatures, caused by its high viscosity, limits the recovery rates and strains the economic viability of these fields. While thermal recovery methods, such as steam injection or THAI, have extensively been applied in the field, their success has so far been limited due to prohibitive heat losses and the difficulty in controlling the combustion process. Electromagnetic (EM) heating via high-frequency EM radiation has attracted attention due to its wide applicability in different environments, its efficiency, and the improved controllability of the heating process. While becoming a promising technology for heavy oil recovery, its effect on overall reservoir production and fluid displacements are poorly understood. Reservoir history matching has become a vital tool for the oil & gas industry to increase recovery rates. Limited research has been undertaken so far to capture the nonlinear reservoir dynamics and significantly varying flow rates for thermally heated heavy oil reservoir that may notably change production rates and render conventional history matching frameworks more challenging. We present a new history matching framework for EM heated heavy oil reservoirs incorporating cross-well seismic imaging. Interfacing an EM heating solver to a reservoir simulator via Andrade’s equation, we couple the system to an ensemble Kalman filter based history matching framework incorporating a cross-well seismic survey module. With increasing power levels and heating applied to the heavy oil reservoirs, reservoir dynamics change considerably and may lead to widely differing production forecasts and increased uncertainty. We have shown that the incorporation of seismic observations into the EnKF framework can significantly enhance reservoir simulations, decrease forecasting

  2. Tracer applications in oil reservoirs in Brazil

    International Nuclear Information System (INIS)

    Moreira, R.M.; Ferreira Pinto, A.M.

    2004-01-01

    Radiotracer applications in oil reservoirs in Brazil started in 1997 at the request of the State Oil Company (Petrobras) at the Carmoplois oilfield. 1 Ci of HTO was injected in a regular five-spot plot and the results obtained were quite satisfactory. Shortly after this test one other request asked for distinguishing the contribution of different injection wells to a production well. It was then realized that other tracers should be available. As a first choice 35 SCN - has been selected since it could be produced at CDTN. An alternative synthesis path was defined which shortened post-irradiation manipulations. The tracer was tested in core samples and a field injection, simultaneously with HTO, was carried out at the Buracica field; again the HTO performed well but 35 SCN - showed up well ahead. Presently the HTO applications are being done on a routine basis. All in all, four tests were performed (some are still ongoing), and the detection limits for both 3 H and 35 S were optimized by refining the sample preparation stage. Lanthanide complexes used as activable tracers are also an appealing option, however core tests performed so far with La-, Ce- and Eu-EDTA indicated some delay of the tracer, so other complexants such as DOTA are to be tried in further laboratory tests and in a field application. Thus, a deeper understanding of their complexation chemistry and carefully conducted tests must be performed before lanthanide complexes can be qualified as reliable oil reservoir tracers. More recently, Petrobras has been asking for partitioning tracers intended for SOR measurement

  3. A New Way to Calculate Flow Pressure for Low Permeability Oil Well with Partially Penetrating Fracture

    Directory of Open Access Journals (Sweden)

    Xiong Ping

    2018-01-01

    Full Text Available In order to improve the validity of the previous models on calculating flow pressure for oil well with partially perforating fracture, a new physical model that obeys the actual heterogeneous reservoir characteristics was built. Different conditions, including reservoir with impermeable top and bottom borders or the reservoir top which has constant pressure, were considered. Through dimensionless transformation, Laplace transformation, Fourier cosine transformation, separation of variables, and other mathematical methods, the analytical solution of Laplace domain was obtained. By using Stephenson numerical methods, the numerical solution pressure in a real domain was obtained. The results of this method agree with the numerical simulations, suggesting that this new method is reliable. The following sensitivity analysis showed that the pressure dynamic linear flow curve can be divided into four flow streams of early linear flow, midradial flow, advanced spherical flow, and border controlling flow. Fracture length controls the early linear flow. Permeability anisotropy significantly affects the midradial flow. The degree of penetration and fracture orientation dominantly affect the late spherical flow. The boundary conditions and reservoir boundary width mainly affect the border controlling flow. The method can be used to determine the optimal degree of opening shot, vertical permeability, and other useful parameters, providing theoretical guidance for reservoir engineering analysis.

  4. Permeability Estimation of Rock Reservoir Based on PCA and Elman Neural Networks

    Science.gov (United States)

    Shi, Ying; Jian, Shaoyong

    2018-03-01

    an intelligent method which based on fuzzy neural networks with PCA algorithm, is proposed to estimate the permeability of rock reservoir. First, the dimensionality reduction process is utilized for these parameters by principal component analysis method. Further, the mapping relationship between rock slice characteristic parameters and permeability had been found through fuzzy neural networks. The estimation validity and reliability for this method were tested with practical data from Yan’an region in Ordos Basin. The result showed that the average relative errors of permeability estimation for this method is 6.25%, and this method had the better convergence speed and more accuracy than other. Therefore, by using the cheap rock slice related information, the permeability of rock reservoir can be estimated efficiently and accurately, and it is of high reliability, practicability and application prospect.

  5. Liquid oil production from shale gas condensate reservoirs

    Science.gov (United States)

    Sheng, James J.

    2018-04-03

    A process of producing liquid oil from shale gas condensate reservoirs and, more particularly, to increase liquid oil production by huff-n-puff in shale gas condensate reservoirs. The process includes performing a huff-n-puff gas injection mode and flowing the bottom-hole pressure lower than the dew point pressure.

  6. Improved oil recovery using bacteria isolated from North Sea petroleum reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Davey, R.A.; Lappin-Scott, H. [Univ. of Exeter (United Kingdom)

    1995-12-31

    During secondary oil recovery, water is injected into the formation to sweep out the residual oil. The injected water, however, follows the path of least resistance through the high-permeability zones, leaving oil in the low-permeability zones. Selective plugging of these their zones would divert the waterflood to the residual oil and thus increase the life of the well. Bacteria have been suggested as an alternative plugging agent to the current method of polymer injection. Starved bacteria can penetrate deeply into rock formations where they attach to the rock surfaces, and given the right nutrients can grow and produce exo-polymer, reducing the permeability of these zones. The application of microbial enhanced oil recovery has only been applied to shallow, cool, onshore fields to date. This study has focused on the ability of bacteria to enhance oil recovery offshore in the North Sea, where the environment can be considered extreme. A screen of produced water from oil reservoirs (and other extreme subterranean environments) was undertaken, and two bacteria were chosen for further work. These two isolates were able to grow and survive in the presence of saline formation waters at a range of temperatures above 50{degrees}C as facultative anaerobes. When a solution of isolates was passed through sandpacks and nutrients were added, significant reductions in permeabilities were achieved. This was confirmed in Clashach sandstone at 255 bar, when a reduction of 88% in permeability was obtained. Both isolates can survive nutrient starvation, which may improve penetration through the reservoir. Thus, the isolates show potential for field trials in the North Sea as plugging agents.

  7. Expanding solvent SAGD in heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Govind, P.A. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[ConocoPhillips Canada Resources Corp., Calgary, AB (Canada); Das, S.; Wheeler, T.J. [Society of Petroleum Engineers, Richardson, TX (United States)]|[ConocoPhillips Co., Houston, TX (United States); Srinivasan, S. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Texas Univ., Austin, TX (United States)

    2008-10-15

    Steam assisted gravity drainage (SAGD) projects have proven effective for the recovery of oil and bitumen. Expanding solvent (ES) SAGD pilot projects have also demonstrated positive results of improved performance. This paper presented the results of a simulation study that investigated several important factors of the ES-SAGD process, including solvent types; concentration; operating pressure; and injection strategy. The objectives of the study were to examine the effectiveness of the ES-SAGD process in terms of production acceleration and energy requirements; to optimize solvent selection; to understand the effect of dilation in unconsolidated oil sands and the directional impact on reservoir parameters and oil production rate in ES-SAGD; and to understand the impact of operating conditions such as pressure, solvent concentration, circulation preheating period and the role of conduction heating and grid size in this process. The advantages of ES-SAGD over SAGD were also outlined. The paper presented results of sensitivity studies that were conducted on these four factors. Conclusions and recommendations for operating strategy were also offered. It was concluded that dilation is an important factor for SAGD performance at high operating pressure. 8 refs., 15 figs.

  8. Producing Light Oil from a Frozen Reservoir: Reservoir and Fluid Characterization of Umiat Field, National Petroleum Reserve, Alaska

    Energy Technology Data Exchange (ETDEWEB)

    Hanks, Catherine

    2012-12-31

    Umiat oil field is a light oil in a shallow, frozen reservoir in the Brooks Range foothills of northern Alaska with estimated oil-in-place of over 1 billion barrels. Umiat field was discovered in the 1940’s but was never considered viable because it is shallow, in the permafrost, and far from any transportation infrastructure. The advent of modern drilling and production techniques has made Umiat and similar fields in northern Alaska attractive exploration and production targets. Since 2008 UAF has been working with Renaissance Alaska Inc. and, more recently, Linc Energy, to develop a more robust reservoir model that can be combined with rock and fluid property data to simulate potential production techniques. This work will be used to by Linc Energy as they prepare to drill up to 5 horizontal wells during the 2012-2013 drilling season. This new work identified three potential reservoir horizons within the Cretaceous Nanushuk Formation: the Upper and Lower Grandstand sands, and the overlying Ninuluk sand, with the Lower Grandstand considered the primary target. Seals are provided by thick interlayered shales. Reserve estimates for the Lower Grandstand alone range from 739 million barrels to 2437 million barrels, with an average of 1527 million bbls. Reservoir simulations predict that cold gas injection from a wagon-wheel pattern of multilateral injectors and producers located on 5 drill sites on the crest of the structure will yield 12-15% recovery, with actual recovery depending upon the injection pressure used, the actual Kv/Kh encountered, and other geologic factors. Key to understanding the flow behavior of the Umiat reservoir is determining the permeability structure of the sands. Sandstones of the Cretaceous Nanushuk Formation consist of mixed shoreface and deltaic sandstones and mudstones. A core-based study of the sedimentary facies of these sands combined with outcrop observations identified six distinct facies associations with distinctive permeability

  9. Upscaling of permeability heterogeneities in reservoir rocks; an integrated approach

    NARCIS (Netherlands)

    Mikes, D.

    2002-01-01

    This thesis presents a hierarchical and geologically constrained deterministic approach to incorporate small-scale heterogeneities into reservoir flow simulators. We use a hierarchical structure to encompass all scales from laminae to an entire depositional system. For the geological models under

  10. Performance Analysis of Depleted Oil Reservoirs for Underground Gas Storage

    Directory of Open Access Journals (Sweden)

    Dr. C.I.C. Anyadiegwu

    2014-02-01

    Full Text Available The performance of underground gas storage in depleted oil reservoir was analysed with reservoir Y-19, a depleted oil reservoir in Southern region of the Niger Delta. Information on the geologic and production history of the reservoir were obtained from the available field data of the reservoir. The verification of inventory was done to establish the storage capacity of the reservoir. The plot of the well flowing pressure (Pwf against the flow rate (Q, gives the deliverability of the reservoir at various pressures. Results of the estimated properties signified that reservoir Y-19 is a good candidate due to its storage capacity and its flow rate (Q of 287.61 MMscf/d at a flowing pressure of 3900 psig

  11. USE OF POLYMERS TO RECOVER VISCOUS OIL FROM UNCONVENTIONAL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Randall Seright

    2011-09-30

    This final technical progress report summarizes work performed the project, 'Use of Polymers to Recover Viscous Oil from Unconventional Reservoirs.' The objective of this three-year research project was to develop methods using water soluble polymers to recover viscous oil from unconventional reservoirs (i.e., on Alaska's North Slope). The project had three technical tasks. First, limits were re-examined and redefined for where polymer flooding technology can be applied with respect to unfavorable displacements. Second, we tested existing and new polymers for effective polymer flooding of viscous oil, and we tested newly proposed mechanisms for oil displacement by polymer solutions. Third, we examined novel methods of using polymer gels to improve sweep efficiency during recovery of unconventional viscous oil. This report details work performed during the project. First, using fractional flow calculations, we examined the potential of polymer flooding for recovering viscous oils when the polymer is able to reduce the residual oil saturation to a value less than that of a waterflood. Second, we extensively investigated the rheology in porous media for a new hydrophobic associative polymer. Third, using simulation and analytical studies, we compared oil recovery efficiency for polymer flooding versus in-depth profile modification (i.e., 'Bright Water') as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer solution viscosity, (5) polymer or blocking-agent bank size, and (6) relative costs for polymer versus blocking agent. Fourth, we experimentally established how much polymer flooding can reduce the residual oil saturation in an oil-wet core that is saturated with viscous North Slope crude. Finally, an experimental study compared mechanical degradation of an associative polymer with that of a partially hydrolyzed polyacrylamide. Detailed results from the first two years of the project may be

  12. Constructive Activation of Reservoir-Resident Microbes for Enhanced Oil Recovery

    Science.gov (United States)

    DeBruyn, R. P.

    2017-12-01

    Microbial communities living in subsurface oil reservoirs biodegrade oil, producing methane. If this process could create methane within the waterflooded pore spaces of an oilfield, the methane would be expected to remain and occupy pore space, decreasing water relative permeability, diverting water flow, and increasing oil recovery by expanding the swept zone of the waterflood. This approach was tested in an oilfield in northern Montana. Preliminary assessments were made of geochemical conditions and microbiological habitations. Then, a formulation of microbial activators, with composition tailored for the reservoir's conditions, was metered at low rates into the existing injection water system for one year. In the field, the responses observed included improved oil production performance; a slight increase in injection pressure; and increased time needed for tracers to move between injection and producing wells. We interpret these results to confirm that successful stimulation of the microbial community caused more methane to be created within the swept zone of the waterflooded reservoir. When the methane exsolved as water flowed between high-pressure injection and low-pressure production wells, the bubbles occupied pore space, reducing water saturation and relative permeability, and re-directing some water flow to "slower" unswept rock with lower permeability and higher oil saturation. In total, the waterflood's swept zone had been expanded to include previously-unflooded rock. This technology was applied in this field after screening based on careful anaerobic sampling, advanced microbiological analysis, and the ongoing success of its waterflood. No reservoir or geological or geophysical simulation models were employed, and physical modifications to field facilities were minor. This technology of utilizing existing microbial populations for enhanced oil recovery can therefore be considered for deployment into waterfloods where small scale, advanced maturity, or

  13. Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar Sag, Junggar Basin

    Science.gov (United States)

    Cao, Z.

    2015-12-01

    Jimusar Sag, which lies in the Junggar Basin,is one of the most typical tight oil study areas in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oilsfrom the Lucaogou Formation were collected for analysis, such as physical properties, bulk composition, saturated hydrocarbon gas chromatography-mass spectrometry (GC-MS), and the calculation of various biomarker parameters. In addition,source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. Biomarkers of suitable source rocks (TOC>1, S1+S2>6mg/g, 0.7%oil-source correlation. To analyze the hydrocarbon generation history of the Lucaogou source rock, 1D basin modeling was performed. The oil-filling history was also defined by means of basin modeling and microthermometry. The results indicated the presence of low maturity to mature crude oils originating from the burial of terrigenous organic matter beneath a saline lake in the source rocks of mainly type II1kerogen. In addition, a higher proportion of bacteria and algae was shown to contribute to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil-source correlations demonstrated that not all mudstones within the Lucaogou Formation contributed to oil accumulation.Crude oil from the upper and lower sections originated from thin-bedded mudstones interbedded within sweet spot sand bodies. A good coincidence of filling history and hydrocarbon generation history indicated that the Lucaogou reservoir is a typical in situ reservoir. The mudstones over or beneath the sweet spot bodies consisted of natural caprocks and prevented the vertical movement of oil by capillary forces. Despite being thicker, the thick-bedded mudstone between the upper and lower sweet spots had no obvious contribution to

  14. Permeability response of oil-contaminated compacted clays

    International Nuclear Information System (INIS)

    Silvestri, V.; Mikhail, N.; Soulie, M.

    1997-01-01

    This paper presents the results of a laboratory investigation on the behavior of motor oil-contaminated, partially saturated compacted clays. For the study, both a natural clay and an artificially purified kaolinite, contaminated with 0 to 8% of motor oil, were firstly compacted following the ASTM standard procedure. Secondly, permeability tests were carried out in a triaxial cell on 10 cm-diameter compacted clay specimens. The results of the investigation indicate that increasing percentages of motor oil decrease both the optimum water content and the optimum dry density of the two clays. However, whereas the optimum water content on the average decreases by about 6% when the percentage contamination increases from 0 to 8%, the corresponding decrease in the optimum dry density is less than 3%. Even though the optimum dry density decreases as the percentage of oil increases from 0 to 8%, there is, however, a range in oil content varying between 2 and 4% for which the optimum dry density is slightly greater than that of the untreated soils. As far as the permeability tests are concerned, the results indicate that as the percentage of oil increases, the coefficient of permeability decreases substantially, especially for clay specimens which were initially compacted on the dry side of optimum

  15. Design of a lube oil reservoir by using flow calculations

    Energy Technology Data Exchange (ETDEWEB)

    Rinkinen, J; Alfthan, A. [Institute of Hydraulics and Automation IHA, Tampere University of Technology, Tampere (Finland)] Suominen, J. [Institute of Energy and Process Engineering, Tampere University of Technology, Tampere (Finland); Airaksinen, A; Antila, K [R and D Engineer Safematic Oy, Muurame (Finland)

    1998-12-31

    The volume of usual oil reservoir for lubrication oil systems is designed by the traditional rule of thumb so that the total oil volume is theoretically changed in every 30 minutes by rated pumping capacity. This is commonly used settling time for air, water and particles to separate by gravity from the oil returning of the bearings. This leads to rather big volumes of lube oil reservoirs, which are sometimes difficult to situate in different applications. In this presentation traditionally sized lube oil reservoir (8 m{sup 3}) is modelled in rectangular coordinates and laminar oil flow is calculated by using FLUENT software that is based on finite difference method. The results of calculation are velocity and temperature fields inside the reservoir. The velocity field is used to visualize different particle paths through the reservoir. Particles that are studied by the model are air bubbles and water droplets. The interest of the study has been to define the size of the air bubbles that are released and the size of the water droplets that are separated in the reservoir. The velocity field is also used to calculate the modelled circulating time of the oil volume which is then compared with the theoretical circulating time that is obtained from the rated pump flow. These results have been used for designing a new lube oil reservoir. This reservoir has also been modelled and optimized by the aid of flow calculations. The best shape of the designed reservoir is constructed in real size for empirical measurements. Some results of the oil flow measurements are shown. (orig.) 7 refs.

  16. Design of a lube oil reservoir by using flow calculations

    Energy Technology Data Exchange (ETDEWEB)

    Rinkinen, J.; Alfthan, A. [Institute of Hydraulics and Automation IHA, Tampere University of Technology, Tampere (Finland)] Suominen, J. [Institute of Energy and Process Engineering, Tampere University of Technology, Tampere (Finland); Airaksinen, A.; Antila, K. [R and D Engineer Safematic Oy, Muurame (Finland)

    1997-12-31

    The volume of usual oil reservoir for lubrication oil systems is designed by the traditional rule of thumb so that the total oil volume is theoretically changed in every 30 minutes by rated pumping capacity. This is commonly used settling time for air, water and particles to separate by gravity from the oil returning of the bearings. This leads to rather big volumes of lube oil reservoirs, which are sometimes difficult to situate in different applications. In this presentation traditionally sized lube oil reservoir (8 m{sup 3}) is modelled in rectangular coordinates and laminar oil flow is calculated by using FLUENT software that is based on finite difference method. The results of calculation are velocity and temperature fields inside the reservoir. The velocity field is used to visualize different particle paths through the reservoir. Particles that are studied by the model are air bubbles and water droplets. The interest of the study has been to define the size of the air bubbles that are released and the size of the water droplets that are separated in the reservoir. The velocity field is also used to calculate the modelled circulating time of the oil volume which is then compared with the theoretical circulating time that is obtained from the rated pump flow. These results have been used for designing a new lube oil reservoir. This reservoir has also been modelled and optimized by the aid of flow calculations. The best shape of the designed reservoir is constructed in real size for empirical measurements. Some results of the oil flow measurements are shown. (orig.) 7 refs.

  17. Method of improving heterogeneous oil reservoir polymer flooding effect by positively-charged gel profile control

    Science.gov (United States)

    Zhao, Ling; Xia, Huifen

    2018-01-01

    The project of polymer flooding has achieved great success in Daqing oilfield, and the main oil reservoir recovery can be improved by more than 15%. But, for some strong oil reservoir heterogeneity carrying out polymer flooding, polymer solution will be inefficient and invalid loop problem in the high permeability layer, then cause the larger polymer volume, and a significant reduction in the polymer flooding efficiency. Aiming at this problem, it is studied the method that improves heterogeneous oil reservoir polymer flooding effect by positively-charged gel profile control. The research results show that the polymer physical and chemical reaction of positively-charged gel with the residual polymer in high permeability layer can generate three-dimensional network of polymer, plugging high permeable layer, and increase injection pressure gradient, then improve the effect of polymer flooding development. Under the condition of the same dosage, positively-charged gel profile control can improve the polymer flooding recovery factor by 2.3∼3.8 percentage points. Under the condition of the same polymer flooding recovery factor increase value, after positively-charged gel profile control, it can reduce the polymer volume by 50 %. Applying mechanism of positively-charged gel profile control technology is feasible, cost savings, simple construction, and no environmental pollution, therefore has good application prospect.

  18. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    Energy Technology Data Exchange (ETDEWEB)

    Koerner, Roy; Clarke, Don; Walker, Scott

    1999-11-09

    The objectives of this quarterly report was to summarize the work conducted under each task during the reporting period April - June 1998 and to report all technical data and findings as specified in the ''Federal Assistance Reporting Checklist''. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  19. Opportunities to improve oil productivity in unstructured deltaic reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    1991-01-01

    This report contains presentations presented at a technical symposium on oil production. Chapter 1 contains summaries of the presentations given at the Department of Energy (DOE)-sponsored symposium and key points of the discussions that followed. Chapter 2 characterizes the light oil resource from fluvial-dominated deltaic reservoirs in the Tertiary Oil Recovery Information System (TORIS). An analysis of enhanced oil recovery (EOR) and advanced secondary recovery (ASR) potential for fluvial-dominated deltaic reservoirs based on recovery performance and economic modeling as well as the potential resource loss due to well abandonments is presented. Chapter 3 provides a summary of the general reservoir characteristics and properties within deltaic deposits. It is not exhaustive treatise, rather it is intended to provide some basic information about geologic, reservoir, and production characteristics of deltaic reservoirs, and the resulting recovery problems.

  20. Production Characteristics and Reservoir Quality at the Ivanić Oil Field (Croatia) Predicted by Machine Learning System

    OpenAIRE

    Hernitz, Zvonimir; Đureković, Miro; Crnički, Josip

    1996-01-01

    At the Ivanić oil field, hydrocarbons are accumulated in fine tomedium grained litharenits of the Ivanić-Grad Formation (Iva-sandstones member) of Upper Miocene age. Reservoir rocks are dividedinlo eight depositional (production) units (i1- i8). Deposits of eachunit are characterized by their own reservoir quality parameters(porosity, horizontal permeability, net pay ... ). Production characteristicsof 30 wells have been studied by a simple slatistical method. Twomajor production well ca...

  1. Interpreting isotopic analyses of microbial sulfate reduction in oil reservoirs

    Science.gov (United States)

    Hubbard, C. G.; Engelbrektson, A. L.; Druhan, J. L.; Cheng, Y.; Li, L.; Ajo Franklin, J. B.; Coates, J. D.; Conrad, M. E.

    2013-12-01

    Microbial sulfate reduction in oil reservoirs is often associated with secondary production of oil where seawater (28 mM sulfate) is commonly injected to maintain reservoir pressure and displace oil. The hydrogen sulfide produced can cause a suite of operating problems including corrosion of infrastructure, health exposure risks and additional processing costs. We propose that monitoring of the sulfur and oxygen isotopes of sulfate can be used as early indicators that microbial sulfate reduction is occurring, as this process is well known to cause substantial isotopic fractionation. This approach relies on the idea that reactions with reservoir (iron) minerals can remove dissolved sulfide, thereby delaying the transport of the sulfide through the reservoir relative to the sulfate in the injected water. Changes in the sulfate isotopes due to microbial sulfate reduction may therefore be measurable in the produced water before sulfide is detected. However, turning this approach into a predictive tool requires (i) an understanding of appropriate fractionation factors for oil reservoirs, (ii) incorporation of isotopic data into reservoir flow and reactive transport models. We present here the results of preliminary batch experiments aimed at determining fractionation factors using relevant electron donors (e.g. crude oil and volatile fatty acids), reservoir microbial communities and reservoir environmental conditions (pressure, temperature). We further explore modeling options for integrating isotope data and discuss whether single fractionation factors are appropriate to model complex environments with dynamic hydrology, geochemistry, temperature and microbiology gradients.

  2. Investigating Multiphase Flow Phenomena in Fine-Grained Reservoir Rocks: Insights from Using Ethane Permeability Measurements over a Range of Pore Pressures

    Directory of Open Access Journals (Sweden)

    Eric Aidan Letham

    2018-01-01

    Full Text Available The ability to quantify effective permeability at the various fluid saturations and stress states experienced during production from shale oil and shale gas reservoirs is required for efficient exploitation of the resources, but to date experimental challenges prevent measurement of the effective permeability of these materials over a range of fluid saturations. To work towards overcoming these challenges, we measured effective permeability of a suite of gas shales to gaseous ethane over a range of pore pressures up to the saturated vapour pressure. Liquid/semiliquid ethane saturation increases due to adsorption and capillary condensation with increasing pore pressure resulting in decreasing effective permeability to ethane gas. By how much effective permeability to ethane gas decreases with adsorption and capillary condensation depends on the pore size distribution of each sample and the stress state that effective permeability is measured at. Effective permeability decreases more at higher stress states because the pores are smaller at higher stress states. The largest effective permeability drops occur in samples with dominant pore sizes in the mesopore range. These pores are completely blocked due to capillary condensation at pore pressures near the saturated vapour pressure of ethane. Blockage of these pores cuts off the main fluid flow pathways in the rock, thereby drastically decreasing effective permeability to ethane gas.

  3. Increasing heavy oil reserves in the Wilmington Oil Field through advanced reservoir characterization and thermal production technologies. Annual report, March 30, 1995--March 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1997-09-01

    The objective of this project is to increase heavy oil reserves in a portion of the Wilmington Oil Field, near Long Beach, California, by implementing advanced reservoir characterization and thermal production technologies. Based on the knowledge and experience gained with this project, these technologies are intended to be extended to other sections of the Wilmington Oil Field, and, through technology transfer, will be available to increase heavy oil reserves in other slope and basin clastic (SBC) reservoirs. The project involves implementing thermal recovery in the southern half of the Fault Block II-A Tar zone. The existing steamflood in Fault Block II-A has been relatively inefficient due to several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery efficiency and reduce operating costs.

  4. Ranking oil viscosity in heavy-oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Bonnie, R.J.M. [Halliburton Energy Services, Calgary, AB (Canada); Seccombe, J. [BP Alaska, AK (United States)

    2005-11-01

    This paper discussed attempts to identify lower viscosity zones within the Ugnu formation at Milne Point field in Alaska through the use of Nuclear Magnetic Resonance (NMR) measurements. To date, only 1 well has been completed in the Ugnu, and BP Alaska is now engaged in studies to find ways to commercialize the formation. While geochemical analysis of oil samples extracted from sidewall cores has successfully identified sweet spots, the costs are prohibitive and they are too slow for real-time decision-making. NMR data acquisition offers a more economical, continuous and almost instantaneous alternative. Two wells were logged and analyzed using both logging while drilling (LWD) NMR and wire log (WL)-NMR tools. With the WL-NMR tool, data were collected in continuous passes and in a series of 45 minute stationary points, acquiring both routine T{sub 2} and diffusion editing data to predict oil viscosity. The LWD-NMR tool was set up to acquire T{sub 1} data when drilling. Forward modelling was used to generate NMR T{sub 2} spectra for reservoir parameters. The NMR logs indicate that the technology is a viable non-radioactive porosity measurement alternative. Data quality had high-vertical resolution and spectral resolution and showed good agreement with density-derived porosity. Zones with viscous oil were located and findings were validated by geochemical analyses. Bandwidth limitation was the only obstacle that prevented real time application of the NMR ranking process. 6 refs., 11 figs.

  5. Optimization of Spore Forming Bacteria Flooding for Enhanced Oil Recovery in North Sea Chalk Reservoir

    DEFF Research Database (Denmark)

    Halim, Amalia Yunita; Nielsen, Sidsel Marie; Eliasson Lantz, Anna

    2015-01-01

    .2-3.8 cm) during bacteria injection. Further seawater flooding after three days shut in period showed that permeability gradually increased in the first two sections of the core and started to decrease in the third section of the core (3.8-6.3 cm). Complete plugging was never observed in our experiments.......Little has been done to study microbial enhanced oil recovery (MEOR) in chalk reservoirs. The present study focused on core flooding experiments to see microbial plugging and its effect on oil recovery. A pressure tapped core holder with pressure ports at 1.2 cm, 3.8 cm, and 6.3 cm from the inlet...

  6. Geological Characterisation of Depleted Oil and Gas Reservoirs for ...

    African Journals Online (AJOL)

    Dr Tse

    The reservoir formation consists of multilayered alternating beds of sandstone and shale cap rocks ... In the oil sector, Nigeria is one of the highest emitters ... Industrial emission and flaring .... integration of the 3D seismic data and wireline logs.

  7. Increasing Waterflood Reserves in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    Energy Technology Data Exchange (ETDEWEB)

    Clarke, D.; Koerner, R.; Moos D.; Nguyen, J.; Phillips, C.; Tagbor, K.; Walker, S.

    1999-04-05

    This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate.

  8. Mapping the Fluid Pathways and Permeability Barriers of a Large Gas Hydrate Reservoir

    Science.gov (United States)

    Campbell, A.; Zhang, Y. L.; Sun, L. F.; Saleh, R.; Pun, W.; Bellefleur, G.; Milkereit, B.

    2012-12-01

    An understanding of the relationship between the physical properties of gas hydrate saturated sedimentary basins aids in the detection, exploration and monitoring one of the world's upcoming energy resources. A large gas hydrate reservoir is located in the MacKenzie Delta of the Canadian Arctic and geophysical logs from the Mallik test site are available for the gas hydrate stability zone (GHSZ) between depths of approximately 850 m to 1100 m. The geophysical data sets from two neighboring boreholes at the Mallik test site are analyzed. Commonly used porosity logs, as well as nuclear magnetic resonance, compressional and Stoneley wave velocity dispersion logs are used to map zones of elevated and severely reduced porosity and permeability respectively. The lateral continuity of horizontal permeability barriers can be further understood with the aid of surface seismic modeling studies. In this integrated study, the behavior of compressional and Stoneley wave velocity dispersion and surface seismic modeling studies are used to identify the fluid pathways and permeability barriers of the gas hydrate reservoir. The results are compared with known nuclear magnetic resonance-derived permeability values. The aim of investigating this heterogeneous medium is to map the fluid pathways and the associated permeability barriers throughout the gas hydrate stability zone. This provides a framework for an understanding of the long-term dissociation of gas hydrates along vertical and horizontal pathways, and will improve the knowledge pertaining to the production of such a promising energy source.

  9. Mixed Finite Element Simulation with Stability Analysis for Gas Transport in Low-Permeability Reservoirs

    Directory of Open Access Journals (Sweden)

    Mohamed F. El-Amin

    2018-01-01

    Full Text Available Natural gas exists in considerable quantities in tight reservoirs. Tight formations are rocks with very tiny or poorly connected pors that make flow through them very difficult, i.e., the permeability is very low. The mixed finite element method (MFEM, which is locally conservative, is suitable to simulate the flow in porous media. This paper is devoted to developing a mixed finite element (MFE technique to simulate the gas transport in low permeability reservoirs. The mathematical model, which describes gas transport in low permeability formations, contains slippage effect, as well as adsorption and diffusion mechanisms. The apparent permeability is employed to represent the slippage effect in low-permeability formations. The gas adsorption on the pore surface has been described by Langmuir isotherm model, while the Peng-Robinson equation of state is used in the thermodynamic calculations. Important compatibility conditions must hold to guarantee the stability of the mixed method by adding additional constraints to the numerical discretization. The stability conditions of the MFE scheme has been provided. A theorem and three lemmas on the stability analysis of the mixed finite element method (MFEM have been established and proven. A semi-implicit scheme is developed to solve the governing equations. Numerical experiments are carried out under various values of the physical parameters.

  10. Discussion of the feasibility of air injection for enhanced oil recovery in shale oil reservoirs

    Directory of Open Access Journals (Sweden)

    Hu Jia

    2017-06-01

    Full Text Available Air injection in light oil reservoirs has received considerable attention as an effective, improved oil recovery process, based primarily on the success of several projects within the Williston Basin in the United States. The main mechanism of air injection is the oxidation behavior between oxygen and crude oil in the reservoir. Air injection is a good option because of its wide availability and low cost. Whether air injection can be applied to shale is an interesting topic from both economic and technical perspectives. This paper initiates a comprehensive discussion on the feasibility and potential of air injection in shale oil reservoirs based on state-of-the-art literature review. Favorable and unfavorable effects of using air injection are discussed in an analogy analysis on geology, reservoir features, temperature, pressure, and petrophysical, mineral and crude oil properties of shale oil reservoirs. The available data comparison of the historically successful air injection projects with typical shale oil reservoirs in the U.S. is summarized in this paper. Some operation methods to improve air injection performance are recommended. This paper provides an avenue for us to make use of many of the favorable conditions of shale oil reservoirs for implementing air injection, or air huff ‘n’ puff injection, and the low cost of air has the potential to improve oil recovery in shale oil reservoirs. This analysis may stimulate further investigation.

  11. Validating predictions of evolving porosity and permeability in carbonate reservoir rocks exposed to CO2-brine

    Science.gov (United States)

    Smith, M. M.; Hao, Y.; Carroll, S.

    2017-12-01

    Improving our ability to better forecast the extent and impact of changes in porosity and permeability due to CO2-brine-carbonate reservoir interactions should lower uncertainty in long-term geologic CO2 storage capacity estimates. We have developed a continuum-scale reactive transport model that simulates spatial and temporal changes to porosity, permeability, mineralogy, and fluid composition within carbonate rocks exposed to CO2 and brine at storage reservoir conditions. The model relies on two primary parameters to simulate brine-CO2-carbonate mineral reaction: kinetic rate constant(s), kmineral, for carbonate dissolution; and an exponential parameter, n, relating porosity change to resulting permeability. Experimental data collected from fifteen core-flooding experiments conducted on samples from the Weyburn (Saskatchewan, Canada) and Arbuckle (Kansas, USA) carbonate reservoirs were used to calibrate the reactive-transport model and constrain the useful range of k and n values. Here we present the results of our current efforts to validate this model and the use of these parameter values, by comparing predictions of extent and location of dissolution and the evolution of fluid permeability against our results from new core-flood experiments conducted on samples from the Duperow Formation (Montana, USA). Agreement between model predictions and experimental data increase our confidence that these parameter ranges need not be considered site-specific but may be applied (within reason) at various locations and reservoirs. This work was performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344.

  12. INCREASING WATERFLOOD RESERVES IN THE WILMINGTON OIL FIELD THROUGH IMPROVED RESERVOIR CHARACTERIZATION AND RESERVOIR MANAGEMENT

    Energy Technology Data Exchange (ETDEWEB)

    Scott Walker; Chris Phillips; Roy Koerner; Don Clarke; Dan Moos; Kwasi Tagbor

    2002-02-28

    This project increased recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs. Transferring technology so that it can be applied in other sections of the Wilmington Field and by operators in other slope and basin reservoirs is a primary component of the project. This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate. Although these reservoirs have been waterflooded over 40 years, researchers have found areas of remaining oil saturation. Areas such as the top sand in the Upper Terminal Zone Fault Block V, the western fault slivers of Upper Terminal Zone Fault Block V, the bottom sands of the Tar Zone Fault Block V, and the eastern edge of Fault Block IV in both the Upper Terminal and Lower Terminal Zones all show significant remaining oil saturation. Each area of interest was uncovered emphasizing a different type of reservoir characterization technique or practice. This was not the original strategy but was necessitated by the different levels of progress in each of the project activities.

  13. Investigation of oil production conditions and production operation by solution gas drive in low permeable heterogeneous limestones

    Energy Technology Data Exchange (ETDEWEB)

    Lillie, W

    1966-04-01

    It was the purpose of this study to investigate the production of oil and gas from a low permeable heterogeneous limestone-reservoir by solution gas drive. The rock-samples were subjected to extensive petrolphysical analyses in order to characterize the pore structure of of the limestone material. Laboratory model flow tests were undertaken to outline in detail the production history during the pressure depletion process under reservoir conditions and by using original reservoir fluids. The experiments were carried out at different rates of pressure decline. It can be stated that the rate of pressure decline is the most important factor affecting the oil recovery and the development of the gas-oil-ratio in a model flow test. The present investigation leads to the following conclusion: It is posible to get reliable results which could be the base for a reservoir performance prediction only when the gas and oil phase are maintained at equilibrium conditions within the rock sample during the pressure decline. An additional calculation of the solution gas drive reservoir production history by the Tarner method shows a good agreement of the experimental and the calculated data. (40 refs.)

  14. Enhanced heavy oil recovery for carbonate reservoirs integrating cross-well seismic–a synthetic Wafra case study

    KAUST Repository

    Katterbauer, Klemens

    2015-07-14

    Heavy oil recovery has been a major focus in the oil and gas industry to counter the rapid depletion of conventional reservoirs. Various techniques for enhancing the recovery of heavy oil were developed and pilot-tested, with steam drive techniques proven in most circumstances to be successful and economically viable. The Wafra field in Saudi Arabia is at the forefront of utilizing steam recovery for carbonate heavy oil reservoirs in the Middle East. With growing injection volumes, tracking the steam evolution within the reservoir and characterizing the formation, especially in terms of its porosity and permeability heterogeneity, are key objectives for sound economic decisions and enhanced production forecasts. We have developed an integrated reservoir history matching framework using ensemble based techniques incorporating seismic data for enhancing reservoir characterization and improving history matches. Examining the performance on a synthetic field study of the Wafra field, we could demonstrate the improved characterization of the reservoir formation, determining more accurately the position of the steam chambers and obtaining more reliable forecasts of the reservoir’s recovery potential. History matching results are fairly robust even for noise levels up to 30%. The results demonstrate the potential of the integration of full-waveform seismic data for steam drive reservoir characterization and increased recovery efficiency.

  15. Permeability model of tight reservoir sandstones combining core-plug and miniperm analysis of drillcore; longyearbyen co2lab, Svalbard

    NARCIS (Netherlands)

    Magnabosco, Cara; Braathen, Alvar; Ogata, Kei

    2014-01-01

    Permeability measurements in Mesozoic, low-permeability sandstone units within the strata cored in seven drillholes near Longyearbyen, Svalbard, have been analysed to assess the presence of aquifers and their potentials as reservoirs for the storage of carbon dioxide. These targeted sandstones are

  16. Isotopic insights into microbial sulfur cycling in oil reservoirs

    Directory of Open Access Journals (Sweden)

    Christopher G Hubbard

    2014-09-01

    Full Text Available Microbial sulfate reduction in oil reservoirs (biosouring is often associated with secondary oil production where seawater containing high sulfate concentrations (~28 mM is injected into a reservoir to maintain pressure and displace oil. The sulfide generated from biosouring can cause corrosion of infrastructure, health exposure risks, and higher production costs. Isotope monitoring is a promising approach for understanding microbial sulfur cycling in reservoirs, enabling early detection of biosouring, and understanding the impact of souring. Microbial sulfate reduction is known to result in large shifts in the sulfur and oxygen isotope compositions of the residual sulfate, which can be distinguished from other processes that may be occurring in oil reservoirs, such as precipitation of sulfate and sulfide minerals. Key to the success of this method is using the appropriate isotopic fractionation factors for the conditions and processes being monitored. For a set of batch incubation experiments using a mixed microbial culture with crude oil as the electron donor, we measured a sulfur fractionation factor for sulfate reduction of -30‰. We have incorporated this result into a simplified 1D reservoir reactive transport model to highlight how isotopes can help discriminate between biotic and abiotic processes affecting sulfate and sulfide concentrations. Modeling results suggest that monitoring sulfate isotopes can provide an early indication of souring for reservoirs with reactive iron minerals that can remove the produced sulfide, especially when sulfate reduction occurs in the mixing zone between formation waters containing elevated concentrations of volatile fatty acids and injection water containing elevated sulfate. In addition, we examine the role of reservoir thermal, geochemical, hydrological, operational and microbiological conditions in determining microbial souring dynamics and hence the anticipated isotopic signatures.

  17. Study on detailed geological modelling for fluvial sandstone reservoir in Daqing oil field

    Energy Technology Data Exchange (ETDEWEB)

    Zhao Hanqing; Fu Zhiguo; Lu Xiaoguang [Institute of Petroleum Exploration and Development, Daqing (China)

    1997-08-01

    Guided by the sedimentation theory and knowledge of modern and ancient fluvial deposition and utilizing the abundant information of sedimentary series, microfacies type and petrophysical parameters from well logging curves of close spaced thousands of wells located in a large area. A new method for establishing detailed sedimentation and permeability distribution models for fluvial reservoirs have been developed successfully. This study aimed at the geometry and internal architecture of sandbodies, in accordance to their hierarchical levels of heterogeneity and building up sedimentation and permeability distribution models of fluvial reservoirs, describing the reservoir heterogeneity on the light of the river sedimentary rules. The results and methods obtained in outcrop and modem sedimentation studies have successfully supported the study. Taking advantage of this method, the major producing layers (PI{sub 1-2}), which have been considered as heterogeneous and thick fluvial reservoirs extending widely in lateral are researched in detail. These layers are subdivided into single sedimentary units vertically and the microfacies are identified horizontally. Furthermore, a complex system is recognized according to their hierarchical levels from large to small, meander belt, single channel sandbody, meander scroll, point bar, and lateral accretion bodies of point bar. The achieved results improved the description of areal distribution of point bar sandbodies, provide an accurate and detailed framework model for establishing high resolution predicting model. By using geostatistic technique, it also plays an important role in searching for enriched zone of residual oil distribution.

  18. Optimizing geologic CO2 sequestration by injection in deep saline formations below oil reservoirs

    International Nuclear Information System (INIS)

    Han, Weon Shik; McPherson, Brian J.

    2009-01-01

    The purpose of this research is to present a best-case paradigm for geologic CO 2 storage: CO 2 injection and sequestration in saline formations below oil reservoirs. This includes the saline-only section below the oil-water contact (OWC) in oil reservoirs, a storage target neglected in many current storage capacity assessments. This also includes saline aquifers (high porosity and permeability formations) immediately below oil-bearing formations. While this is a very specific injection target, we contend that most, if not all, oil-bearing basins in the US contain a great volume of such strata, and represent a rather large CO 2 storage capacity option. We hypothesize that these are the best storage targets in those basins. The purpose of this research is to evaluate this hypothesis. We quantitatively compared CO 2 behavior in oil reservoirs and brine formations by examining the thermophysical properties of CO 2 , CO 2 -brine, and CO 2 -oil in various pressure, temperature, and salinity conditions. In addition, we compared the distribution of gravity number (N), which characterizes a tendency towards buoyancy-driven CO 2 migration, and mobility ratio (M), which characterizes the impeded CO 2 migration, in oil reservoirs and brine formations. Our research suggests competing advantages and disadvantages of CO 2 injection in oil reservoirs vs. brine formations: (1) CO 2 solubility in oil is significantly greater than in brine (over 30 times); (2) the tendency of buoyancy-driven CO 2 migration is smaller in oil reservoirs because density contrast between oil and CO 2 is smaller than it between brine and oil (the approximate density contrast between CO 2 and crude oil is ∼100 kg/m 3 and between CO 2 and brine is ∼350 kg/m 3 ); (3) the increased density of oil and brine due to the CO 2 dissolution is not significant (about 7-15 kg/m 3 ); (4) the viscosity reduction of oil due to CO 2 dissolution is significant (from 5790 to 98 mPa s). We compared these competing

  19. Well performance relationships in heavy foamy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Kumar, R.; Mahadevan, J. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Tulsa Univ., Tulsa, OK (United States)

    2008-10-15

    The viscosities and thermodynamic properties of heavy oils are different from conventional oils. Heavy oil reservoirs have foamy behaviour and the gas/oil interface stabilizes in the presence of asphaltenes. In the case of conventional oils, gas evolves from the solution when the formation pressure reaches the bubble point pressure. This study modelled the fluid properties of heavy foamy oils and their influence on the inflow performance relationship (IPR). An expression for inflow performance in heavy oil was developed by including the properties of foamy oil into a space averaged flow equation assuming pseudo-steady state conditions. The unique feature of this study was that the density, formation volume factor and solution gas-oil ratio were modelled as functions of entrained gas fraction. The newly developed expression for inflow performance of foamy oils may also be used to model conventional oil inflow by setting the entrained gas fraction to zero in the fluid property models. The results of the inflow performance of foamy oil and conventional oil were compared and an outflow performance relationship was calculated. The study showed that the inflow performance in foamy oil is influenced by entrained gas. The surface flow rates and bottom-hole flow rates are also influenced by the presence of entrained gas, with heavy foamy oil showing a higher volumetric production rate than conventional oil. The outflow performance curve depended on the fluid properties of the foamy oil. A nodal analysis of the well performance showed that the conventional calculation methods underestimate the production from foamy oil wells because they do not consider the effect of entrained gas which lowers density and improves the mobility of foamy oil. 14 refs., 2 tabs., 20 figs., 1 appendix.

  20. Porosity, permeability and 3D fracture network characterisation of dolomite reservoir rock samples.

    Science.gov (United States)

    Voorn, Maarten; Exner, Ulrike; Barnhoorn, Auke; Baud, Patrick; Reuschlé, Thierry

    2015-03-01

    With fractured rocks making up an important part of hydrocarbon reservoirs worldwide, detailed analysis of fractures and fracture networks is essential. However, common analyses on drill core and plug samples taken from such reservoirs (including hand specimen analysis, thin section analysis and laboratory porosity and permeability determination) however suffer from various problems, such as having a limited resolution, providing only 2D and no internal structure information, being destructive on the samples and/or not being representative for full fracture networks. In this paper, we therefore explore the use of an additional method - non-destructive 3D X-ray micro-Computed Tomography (μCT) - to obtain more information on such fractured samples. Seven plug-sized samples were selected from narrowly fractured rocks of the Hauptdolomit formation, taken from wellbores in the Vienna basin, Austria. These samples span a range of different fault rocks in a fault zone interpretation, from damage zone to fault core. We process the 3D μCT data in this study by a Hessian-based fracture filtering routine and can successfully extract porosity, fracture aperture, fracture density and fracture orientations - in bulk as well as locally. Additionally, thin sections made from selected plug samples provide 2D information with a much higher detail than the μCT data. Finally, gas- and water permeability measurements under confining pressure provide an important link (at least in order of magnitude) towards more realistic reservoir conditions. This study shows that 3D μCT can be applied efficiently on plug-sized samples of naturally fractured rocks, and that although there are limitations, several important parameters can be extracted. μCT can therefore be a useful addition to studies on such reservoir rocks, and provide valuable input for modelling and simulations. Also permeability experiments under confining pressure provide important additional insights. Combining these and

  1. Experiences with linear solvers for oil reservoir simulation problems

    Energy Technology Data Exchange (ETDEWEB)

    Joubert, W.; Janardhan, R. [Los Alamos National Lab., NM (United States); Biswas, D.; Carey, G.

    1996-12-31

    This talk will focus on practical experiences with iterative linear solver algorithms used in conjunction with Amoco Production Company`s Falcon oil reservoir simulation code. The goal of this study is to determine the best linear solver algorithms for these types of problems. The results of numerical experiments will be presented.

  2. Heavy oil reservoirs recoverable by thermal technology. Annual report

    Energy Technology Data Exchange (ETDEWEB)

    Kujawa, P.

    1981-02-01

    This volume contains reservoir, production, and project data for target reservoirs thermally recoverable by steam drive which are equal to or greater than 2500 feet deep and contain heavy oil in the 8 to 25/sup 0/ API gravity range. Data were collected from three source types: hands-on (A), once-removed (B), and twice-removed (C). In all cases, data were sought depicting and characterizing individual reservoirs as opposed to data covering an entire field with more than one producing interval or reservoir. The data sources are listed at the end of each case. This volume also contains a complete listing of operators and projects, as well as a bibliography of source material.

  3. Triple-porosity/permeability flow in faulted geothermal reservoirs: Two-dimensional effects

    Energy Technology Data Exchange (ETDEWEB)

    Cesar Suarez Arriaga, M. [Michoacan Univ. & CFE, Mich. (Mexico); Samaniego Verduzco, F. [National Autonomous Univ. of Mexico, Coyoacan (Mexico)

    1995-03-01

    An essential characteristic of some fractured geothermal reservoirs is noticeable when the drilled wells intersect an open fault or macrofracture. Several evidences observed, suggest that the fluid transport into this type of systems, occurs at least in three stages: flow between rock matrix and microfractures, flow between fractures and faults and flow between faults and wells. This pattern flow could define, by analogy to the classical double-porosity model, a triple-porosity, triple-permeability concept. From a mathematical modeling point of view, the non-linearity of the heterogeneous transport processes, occurring with abrupt changes on the petrophysical properties of the rock, makes impossible their exact or analytic solution. To simulate this phenomenon, a detailed two-dimensional geometric model was developed representing the matrix-fracture-fault system. The model was solved numerically using MULKOM with a H{sub 2}O=CO{sub 2} equation of state module. This approach helps to understand some real processes involved. Results obtained from this study, exhibit the importance of considering the triple porosity/permeability concept as a dominant mechanism producing, for example, strong pressure gradients between the reservoir and the bottom hole of some wells.

  4. Air injection low temperature oxidation process for enhanced oil recovery from light oil reservoirs

    International Nuclear Information System (INIS)

    Tunio, A.H.; Harijan, K.

    2010-01-01

    This paper represents EOR (Enhanced Oil Recovery) methods to recover unswept oil from depleted light oil reservoirs. The essential theme here is the removal of oxygen at LTO (Low Temperature Oxidation) from the injected air for a light oil reservoir by means of some chemical reactions occurring between oil and oxygen. In-situ combustion process, HTO (High Temperature Oxidation) is not suitable for deep light oil reservoirs. In case of light oil reservoirs LTO is more suitable to prevail as comparative to HTO. Few laboratory experimental results were obtained from air injection process, to study the LTO reactions. LTO process is suitable for air injection rate in which reservoir has sufficiently high temperature and spontaneous reaction takes place. Out comes of this study are the effect of LTO reactions in oxygen consumption and the recovery of oil. This air injection method is economic compared to other EOR methods i.e. miscible hydrocarbon gas, nitrogen, and carbon dioxide flooding etc. This LTO air injection process is suitable for secondary recovery methods where water flooding is not feasible due to technical problems. (author)

  5. Transport of Gas Phase Radionuclides in a Fractured, Low-Permeability Reservoir

    Science.gov (United States)

    Cooper, C. A.; Chapman, J.

    2001-12-01

    The U.S. Atomic Energy Commission (predecessor to the Department of Energy, DOE) oversaw a joint program between industry and government in the 1960s and 1970s to develop technology to enhance production from low-permeability gas reservoirs using nuclear stimulation rather than conventional means (e.g., hydraulic and/or acid fracturing). Project Rio Blanco, located in the Piceance Basin, Colorado, was the third experiment under the program. Three 30-kiloton nuclear explosives were placed in a 2134 m deep well at 1780, 1899, and 2039 m below the land surface and detonated in May 1973. Although the reservoir was extensively fractured, complications such as radionuclide contamination of the gas prevented production and subsequent development of the technology. Two-dimensional numerical simulations were conducted to identify the main transport processes that have occurred and are currently occurring in relation to the detonations, and to estimate the extent of contamination in the reservoir. Minor modifications were made to TOUGH2, the multiphase, multicomponent reservoir simulator developed at Lawrence Berkeley National Laboratories. The simulator allows the explicit incorporation of fractures, as well as heat transport, phase change, and first order radionuclide decay. For a fractured two-phase (liquid and gas) reservoir, the largest velocities are of gases through the fractures. In the gas phase, tritium and one isotope of krypton are the principle radionuclides of concern. However, in addition to existing as a fast pathway, fractures also permit matrix diffusion as a retardation mechanism. Another retardation mechanism is radionuclide decay. Simulations show that incorporation of fractures can significantly alter transport rates, and that radionuclides in the gas phase can preferentially migrate upward due to the downward gravity drainage of liquid water in the pores. This project was funded by the National Nuclear Security Administration, Nevada Operations Office

  6. The Tianjin geothermal field (north-eastern China): Water chemistry and possible reservoir permeability reduction phenomena

    Energy Technology Data Exchange (ETDEWEB)

    Minissale, Angelo; Montegrossi, Giordano; Orlando, Andrea [Institute of Geosciences and Earth Resources, National Research Council of Italy (CNR), Via G. La Pira 4, 50121 Florence (Italy); Borrini, Daniele; Tassi, Franco [Department of Earth Sciences, University of Florence, Via G. La Pira 4, 50121 Florence (Italy); Vaselli, Orlando [Institute of Geosciences and Earth Resources, National Research Council of Italy (CNR), Via G. La Pira 4, 50121 Florence (Italy); Department of Earth Sciences, University of Florence, Via G. La Pira 4, 50121 Florence (Italy); Huertas, Antonio Delgado [Estacion Experimental de Zaidin (CSIC), Prof. Albareda 1, 18008 Granada (Spain); Yang, Jincheng; Cheng, Wanquing [Aode Renewable Energy Research Institute, 90 Weijin South Road, Nankai District, 300381 Tianjin (China); Tedesco, Dario [Department of Environmental Sciences, Second University of Naples, Via Vivaldi 43, Caserta 81100 (Italy); Institute of Environmental Geology and Geo Engineering (CNR), Piazzale A. Moro 5, Roma 00100 (Italy); Poreda, Robert [Department of Earth and Environmental Sciences, University of Rochester, 227 Hutchison Hall, Rochester, NY 14627 (United States)

    2008-08-15

    Injection of spent (cooled) thermal fluids began in the Tianjin geothermal district, north-eastern China, at the end of the 1990s. Well injectivities declined after 3-4 years because of self-sealing processes that reduced reservoir permeability. The study focuses on the factors that may have caused the observed decrease in permeability, using chemical and isotopic data on fluids (water and gas) and mineral phases collected from production and injection wells. The results of data processing and interpretation indicate that (1) it is very unlikely that calcite and silica precipitation is taking place in the reservoir; (2) the Fe- and Zn-rich mineral phases (e.g. sulfides, hydroxides and silicates) show positive saturation indexes; (3) SEM and XRD analyses of filtered material reveal that the latter mineral phases are common; (4) visual observation of casings and surface installations, and of corrosion products, suggests that a poor quality steel was used in their manufacture; (5) significant quantities of solids (e.g. quartz and feldspar crystals) are carried by the geothermal fluid; (6) seasonal changes in fluid composition lead to a reduction in casing corrosion during the summer. It was concluded that the decrease in injectivity in the Tianjin wells is caused only in part by the oxidation of casings, downhole pumps, and surface installations, triggered by free oxygen in the injected fluids; the utilization of better quality steels should drastically reduce this type of corrosion. Self-sealing of pores and fractures by reservoir formation solids and by the Fe-corrosion products suspended in the injected fluids seems to be a more important phenomenon, whose effect could be greatly reduced by installing filtering devices at all sites. (author)

  7. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    International Nuclear Information System (INIS)

    Grigg, Reid B.

    2002-01-01

    A three-year contract, DOE Contract No. DE-FG26-01BC15364 ''Improving CO 2 Efficiency for Recovering Oil in Heterogeneous Reservoirs,'' was started on September 28, 2001. This project examines three major areas in which CO 2 flooding can be improved: fluid and matrix interactions, conformance control/sweep efficiency, and reservoir simulation for improved oil recovery. This report discusses the activity during the six-month period covering January 1, 2002 through June 30, 2002 that covers the second and third fiscal quarters of the project's first year. Paper SPE 75178, ''Cost Reduction and Injectivity Improvements for CO 2 Foams for Mobility Control,'' has been presented and included in the proceedings of the SPE/DOE Thirteenth Symposium on Improved Oil Recovery, Tulsa, OK, April 13-17, 2002. During these two quarters of the project we have been working in several areas: reservoir fluid/rock interactions and their relationships to changing injectivity, producer survey on injectivity, and surfactant adsorption on quarried and reservoir core

  8. Investigation of Primary Recovery in Low-Permeability Oil Formations: A Look at the Cardium Formation, Alberta (Canada

    Directory of Open Access Journals (Sweden)

    Ghaderi S.M.

    2014-12-01

    Full Text Available Tight oil formations (permeability < 1 mD in Western Canada have recently emerged as a reliable resource of light oil supply owing to the use of multifractured horizontal wells. The Cardium formation, which contains 25% of Alberta’s total discovered light oil (according to Alberta Energy Resources Conservation Board, consists of conventional and unconventional (low-permeability or tight play areas. The conventional play areas have been developed since 1957. Contrarily, the development of unconventional play is a recent event, due to considerably poorer reservoir properties which increases the risk associated with capital investment. This in turn implies the need for a comprehensive and critical study of the area before planning any development strategy. This paper presents performance results from the low permeability portions of the Cardium formation where new horizontal wells have been drilled and stimulated in multiple stages to promote transverse hydraulic fractures. Development of the tight Cardium formation using primary recovery is considered. The production data of these wells was first matched using a black oil simulator. The calibrated model presented was used for performance perditions based on sensitivity studies and investigations that encompassed design factors such as well spacing, fracture properties and operational constraints.

  9. MEOR (microbial enhanced oil recovery) data base and evaluation of reservoir characteristics for MEOR projects

    Energy Technology Data Exchange (ETDEWEB)

    Bryant, R.S.

    1989-09-01

    One aspect of NIPER's microbial enhanced oil recovery (MEOR) research program has been focused on obtaining all available information regarding the use of microorganisms in enhanced oil recovery field projects. The data have been evaluated in order to construct a data base of MEOR field projects. The data base has been used in this report to present a list of revised reservoir screening criteria for MEOR field processes. This list is by no means complete; however, until more information is available from ongoing field tests, it represents the best available data to date. The data base has been studied in this report in order to determine any significant reports from MEOR field projects where the microbial treatment was unsuccessful. Such information could indicate limitations of MEOR processes. The types of reservoir information sought from these projects that could be limitations of microorganisms include reservoir permeability, salinity, temperature, and high concentrations of minerals in the rock such as selenium, arsenic, or mercury. Unfortunately, most of the MEOR field projects to date have not reported this type of information; thus we still cannot assess field limitations until more projects report these data. 7 refs., 1 fig., 7 tabs.

  10. Real Time Oil Reservoir Evaluation Using Nanotechnology

    Science.gov (United States)

    Li, Jing (Inventor); Meyyappan, Meyya (Inventor)

    2011-01-01

    A method and system for evaluating status and response of a mineral-producing field (e.g., oil and/or gas) by monitoring selected chemical and physical properties in or adjacent to a wellsite headspace. Nanotechnology sensors and other sensors are provided for one or more underground (fluid) mineral-producing wellsites to determine presence/absence of each of two or more target molecules in the fluid, relative humidity, temperature and/or fluid pressure adjacent to the wellsite and flow direction and flow velocity for the fluid. A nanosensor measures an electrical parameter value and estimates a corresponding environmental parameter value, such as water content or hydrocarbon content. The system is small enough to be located down-hole in each mineral-producing horizon for the wellsite.

  11. Class III Mid-Term Project, "Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies"

    Energy Technology Data Exchange (ETDEWEB)

    Scott Hara

    2007-03-31

    geomechanical characteristics of the producing formations. The objectives were to further improve reservoir characterization of the heterogeneous turbidite sands, test the proficiency of the three-dimensional geologic and thermal reservoir simulation models, identify the high permeability thief zones to reduce water breakthrough and cycling, and analyze the nonuniform distribution of the remaining oil in place. This work resulted in the redevelopment of the Tar II-A and Tar V post-steamflood projects by drilling several new wells and converting idle wells to improve injection sweep efficiency and more effectively drain the remaining oil reserves. Reservoir management work included reducing water cuts, maintaining or increasing oil production, and evaluating and minimizing further thermal-related formation compaction. The BP2 project utilized all the tools and knowledge gained throughout the DOE project to maximize recovery of the oil in place.

  12. Multicomponent seismic reservoir characterization of a steam-assisted gravity drainage (SAGD) heavy oil project, Athabasca oil sands, Alberta

    Science.gov (United States)

    Schiltz, Kelsey Kristine

    Steam-assisted gravity drainage (SAGD) is an in situ heavy oil recovery method involving the injection of steam in horizontal wells. Time-lapse seismic analysis over a SAGD project in the Athabasca oil sands deposit of Alberta reveals that the SAGD steam chamber has not developed uniformly. Core data confirm the presence of low permeability shale bodies within the reservoir. These shales can act as barriers and baffles to steam and limit production by prohibiting steam from accessing the full extent of the reservoir. Seismic data can be used to identify these shale breaks prior to siting new SAGD well pairs in order to optimize field development. To identify shale breaks in the study area, three types of seismic inversion and a probabilistic neural network prediction were performed. The predictive value of each result was evaluated by comparing the position of interpreted shales with the boundaries of the steam chamber determined through time-lapse analysis. The P-impedance result from post-stack inversion did not contain enough detail to be able to predict the vertical boundaries of the steam chamber but did show some predictive value in a spatial sense. P-impedance from pre-stack inversion exhibited some meaningful correlations with the steam chamber but was misleading in many crucial areas, particularly the lower reservoir. Density estimated through the application of a probabilistic neural network (PNN) trained using both PP and PS attributes identified shales most accurately. The interpreted shales from this result exhibit a strong relationship with the boundaries of the steam chamber, leading to the conclusion that the PNN method can be used to make predictions about steam chamber growth. In this study, reservoir characterization incorporating multicomponent seismic data demonstrated a high predictive value and could be useful in evaluating future well placement.

  13. Solubility and Permeability Studies of Aceclofenac in Different Oils

    African Journals Online (AJOL)

    The solubility and permeability of aceclofenac were compared with the hydroalcoholic solution of ... the use of lipid based systems such as micro- or .... carriers/vehicles for enhanced solubility and permeability ... modifications: A recent review.

  14. Hydrocarbon Potential in Sandstone Reservoir Isolated inside Low Permeability Shale Rock (Case Study: Beruk Field, Central Sumatra Basin)

    Science.gov (United States)

    Diria, Shidqi A.; Musu, Junita T.; Hasan, Meutia F.; Permono, Widyo; Anwari, Jakson; Purba, Humbang; Rahmi, Shafa; Sadjati, Ory; Sopandi, Iyep; Ruzi, Fadli

    2018-03-01

    Upper Red Bed, Menggala Formation, Bangko Formation, Bekasap Formation and Duri Formationare considered as the major reservoirs in Central Sumatra Basin (CSB). However, Telisa Formation which is well-known as seal within CSB also has potential as reservoir rock. Field study discovered that lenses and layers which has low to high permeability sandstone enclosed inside low permeability shale of Telisa Formation. This matter is very distinctive and giving a new perspective and information related to the invention of hydrocarbon potential in reservoir sandstone that isolated inside low permeability shale. This study has been conducted by integrating seismic data, well logs, and petrophysical data throughly. Facies and static model are constructed to estimate hydrocarbon potential resource. Facies model shows that Telisa Formation was deposited in deltaic system while the potential reservoir was deposited in distributary mouth bar sandstone but would be discontinued bedding among shale mud-flat. Besides, well log data shows crossover between RHOB and NPHI, indicated that distributary mouth bar sandstone is potentially saturated by hydrocarbon. Target area has permeability ranging from 0.01-1000 mD, whereas porosity varies from 1-30% and water saturation varies from 30-70%. The hydrocarbon resource calculation approximates 36.723 MSTB.

  15. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    International Nuclear Information System (INIS)

    Reid B. Grigg; Robert K. Svec; Zheng-Wen Zeng; Liu Yi; Baojun Bai

    2004-01-01

    A three-year contract for the project, DOE Contract No. DE-FG26-01BC15364, ''Improving CO 2 Efficiency for Recovering Oil in Heterogeneous Reservoirs'', was started on September 28, 2001. This project examines three major areas in which CO 2 flooding can be improved: fluid and matrix interactions, conformance control/sweep efficiency, and reservoir simulation for improved oil recovery. The project has received a one-year, no-cost extension to September 27, 2005. During this extra time additional deliverables will be (1) the version of MASTER that has been debugged and a foam option added for CO 2 mobility control and (2) adsorption/desorption data on pure component minerals common in reservoir rock that will be used to improve predictions of chemical loss to adsorption in reservoirs. This report discusses the activity during the six-month period covering October 1, 2003 through March 31, 2004 that comprises the first and second fiscal quarters of the project's third year. During this period of the project several areas have advanced: reservoir fluid/rock interactions and their relationships to changing injectivity, and surfactant adsorption on quarried core and pure component granules, foam stability, and high flow rate effects. Presentations and papers included: a papers covered in a previous report was presented at the fall SPE ATCE in Denver in October 2003, a presentation at the Southwest ACS meeting in Oklahoma City, presentation on CO 2 flood basic behavior at the Midland Annual CO 2 Conference December 2003; two papers prepared for the biannual SPE/DOE Symposium on IOR, Tulsa, April 2004; one paper accepted for the fall 2004 SPE ATCE in Houston; and a paper submitted to an international journal Journal of Colloid and Interface Science which is being revised after peer review

  16. Estimating reservoir permeability from gravity current modeling of CO2 flow at Sleipner storage project, North Sea

    Science.gov (United States)

    Cowton, L. R.; Neufeld, J. A.; Bickle, M.; White, N.; White, J.; Chadwick, A.

    2017-12-01

    Vertically-integrated gravity current models enable computationally efficient simulations of CO2 flow in sub-surface reservoirs. These simulations can be used to investigate the properties of reservoirs by minimizing differences between observed and modeled CO2 distributions. At the Sleipner project, about 1 Mt yr-1 of supercritical CO2 is injected at a depth of 1 km into a pristine saline aquifer with a thick shale caprock. Analysis of time-lapse seismic reflection surveys shows that CO2 is distributed within 9 discrete layers. The trapping mechanism comprises a stacked series of 1 m thick, impermeable shale horizons that are spaced at 30 m intervals through the reservoir. Within the stratigraphically highest reservoir layer, Layer 9, a submarine channel deposit has been mapped on the pre-injection seismic survey. Detailed measurements of the three-dimensional CO2 distribution within Layer 9 have been made using seven time-lapse surveys, providing a useful benchmark against which numerical flow simulations can be tested. Previous simulations have, in general, been largely unsuccessful in matching the migration rate of CO2 in this layer. Here, CO2 flow within Layer 9 is modeled as a vertically-integrated gravity current that spreads beneath a structurally complex caprock using a two-dimensional grid, considerably increasing computational efficiency compared to conventional three-dimensional simulators. This flow model is inverted to find the optimal reservoir permeability in Layer 9 by minimizing the difference between observed and predicted distributions of CO2 as a function of space and time. A three parameter inverse model, comprising reservoir permeability, channel permeability and channel width, is investigated by grid search. The best-fitting reservoir permeability is 3 Darcys, which is consistent with measurements made on core material from the reservoir. Best-fitting channel permeability is 26 Darcys. Finally, the ability of this simplified numerical model

  17. Capacity expansion analysis of UGSs rebuilt from low-permeability fractured gas reservoirs with CO2 as cushion gas

    Directory of Open Access Journals (Sweden)

    Yufei Tan

    2016-11-01

    Full Text Available The techniques of pressurized mining and hydraulic fracturing are often used to improve gas well productivity at the later development stage of low-permeability carbonate gas reservoirs, but reservoirs are watered out and a great number of micro fractures are produced. Therefore, one of the key factors for underground gas storages (UGS rebuilt from low-permeability fractured gas reservoirs with CO2 as the cushion gas is how to expand storage capacity effectively by injecting CO2 to displace water and to develop control strategies for the stable migration of gas–water interface. In this paper, a mathematical model was established to simulate the gas–water flow when CO2 was injected into dual porosity reservoirs to displace water. Then, the gas–water interface migration rules while CO2 was injected in the peripheral gas wells for water displacement were analyzed with one domestic UGS rebuilt from fractured gas reservoirs as the research object. And finally, discussion was made on how CO2 dissolution, bottom hole flowing pressure (BHFP, CO2 injection rate and micro fracture parameters affect the stability of gas–water interface in the process of storage capacity expansion. It is shown that the speed of capacity expansion reaches the maximum value at the fifth cycle and then decreases gradually when UGS capacity is expanded in the pattern of more injection and less withdrawal. Gas–water interface during UGS capacity expansion is made stable due to that the solubility of CO2 in water varies with the reservoir pressure. When the UGS capacity is expanded at constant BHFP and the flow rate, the expansion speed can be increased effectively by increasing the BHFP and the injection flow rate of gas wells in the central areas appropriately. In the reservoir areas with high permeability and fracture-matrix permeability ratio, the injection flow rate should be reduced properly to prevent gas–water interface fingering caused by a high-speed flow

  18. Physical Aspects in Upscaling of Fractured Reservoirs and Improved Oil Recovery Prediction

    NARCIS (Netherlands)

    Salimi, H.

    2010-01-01

    This thesis is concerned with upscaled models for waterflooded naturally fractured reservoirs (NFRs). Naturally fractured petroleum reservoirs provide over 20% of the world’s oil reserves and production. From the fluid-flow point of view, a fractured reservoir is defined as a reservoir in which a

  19. Reduction of light oil usage as power fluid for jet pumping in deep heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Chen, S.; Li, H.; Yang, D. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[Regina Univ., SK (Canada); Zhang, Q. [China Univ. of Petroleum, Dongying, Shandong (China); He, J. [China National Petroleum Corp., Haidan District, Beijing (China). PetroChina Tarim Oilfield Co.

    2008-10-15

    In deep heavy oil reservoirs, reservoir fluid can flow more easily in the formation as well as around the bottomhole. However, during its path along the production string, viscosity of the reservoir fluid increases dramatically due to heat loss and release of the dissolved gas, resulting in significant pressure drop along the wellbore. Artificial lifting methods need to be adopted to pump the reservoir fluids to the surface. This paper discussed the development of a new technique for reducing the amount of light oil used for jet pumping in deep heavy oil wells. Two approaches were discussed. Approach A uses the light oil as a power fluid first to obtain produced fluid with lower viscosity, and then the produced fluid is reinjected into the well as a power fluid. The process continues until the viscosity of the produced fluid is too high to be utilized. Approach B combines a portion of the produced fluid with the light oil at a reasonable ratio and then the produced fluid-light oil mixture is used as the power fluid for deep heavy oil well production. The viscosity of the blended power fluid continue to increase and eventually reach equilibrium. The paper presented the detailed processes of both approaches in order to indicate how to apply them in field applications. Theoretic models were also developed and presented to determine the key parameters in the field operations. A field case was also presented and a comparison and analysis between the two approaches were discussed. It was concluded from the field applications that, with a certain amount of light oil, the amount of reservoir fluid produced by using the new technique could be 3 times higher than that of the conventional jet pumping method. 17 refs., 3 tabs., 6 figs.

  20. Mechanism for calcite dissolution and its contribution to development of reservoir porosity and permeability in the Kela 2 gas field,Tarim Basin,China

    Institute of Scientific and Technical Information of China (English)

    2008-01-01

    This study is undertaken to understand how calcite precipitation and dissolution contributes to depth-related changes in porosity and permeability of gas-bearing sandstone reservoirs in the Kela 2 gas field of the Tarim Basin, Northwestern China. Sandstone samples and pore water samples are col-lected from well KL201 in the Tarim Basin. Vertical profiles of porosity, permeability, pore water chem-istry, and the relative volume abundance of calcite/dolomite are constructed from 3600 to 4000 m below the ground surface within major oil and gas reservoir rocks. Porosity and permeability values are in-versely correlated with the calcite abundance, indicating that calcite dissolution and precipitation may be controlling porosity and permeability of the reservoir rocks. Pore water chemistry exhibits a sys-tematic variation from the Na2SO4 type at the shallow depth (3600-3630 m), to the NaHCO3 type at the intermediate depth (3630―3695 m),and to the CaCl2 type at the greater depth (3728―3938 m). The geochemical factors that control the calcite solubility include pH, temperature, pressure, Ca2+ concen-tration, the total inorganic carbon concentration (ΣCO2), and the type of pore water. Thermodynamic phase equilibrium and mass conservation laws are applied to calculate the calcite saturation state as a function of a few key parameters. The model calculation illustrates that the calcite solubility is strongly dependent on the chemical composition of pore water, mainly the concentration difference between the total dissolved inorganic carbon and dissolved calcium concentration (i.e., [ΣCO2] -[Ca2+]). In the Na2SO4 water at the shallow depth, this index is close to 0, pore water is near the calcite solubility. Calcite does not dissolve or precipitate in significant quantities. In the NaHCO3 water at the intermedi-ate depth, this index is greater than 0, and pore water is supersaturated with respect to calcite. Massive calcite precipitation was observed at this depth

  1. Predicting permeability of low enthalpy geothermal reservoirs: A case study from the Upper Triassic − Lower Jurassic Gassum Formation, Norwegian–Danish Basin

    DEFF Research Database (Denmark)

    Weibel, Rikke; Olivarius, Mette; Kristensen, Lars

    2017-01-01

    This paper aims at improving the predictability of permeability in low enthalpy geothermal reser-voirs by investigating the effect of diagenesis on sandstone permeability. Applying the best fittedporosity–permeability trend lines, obtained from conventional core analysis, to log-interpreted poros...

  2. Electro-magnetic heating in viscous oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Das, S. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Marathon Oil Corp., Houston, TX (United States)

    2008-10-15

    This paper discussed electromagnetic (EM) heating techniques for primary and secondary enhanced oil recovery (EOR) processes. Ohmic, induction, and formation resistive heating techniques were discussed. Issues related to energy equivalence and hardware requirements were reviewed. Challenges related to heat losses in vertical wellbores, well integrity, and galvanic corrosion were also outlined. A pair of 1500 foot horizontal wells in a heavy oil reservoir were then modelled in order to optimize EM recovery processes. DC current was used in a base case water flood run. Electrical conductivities were measured. The model was converted to a homogenous model in order to study injector and producer electrodes. The study showed that reservoir resistance was low, and most of the heating took place near the electrode area where electric lines diverged or converged. Results of the study suggested that EM heating in formations is not as efficient as steam-based processes. Accurate simulations of EM heating processes within reservoirs are difficult to obtain, as the amounts of estimated heat input are sensitive to grid refinement. It was concluded that hot spots in the EM electrodes have also caused failures in other field applications and studies. 11 refs., 12 figs.

  3. Conversion of Crude Oil to Methane by a Microbial Consortium Enriched From Oil Reservoir Production Waters

    Directory of Open Access Journals (Sweden)

    Carolina eBerdugo-Clavijo

    2014-05-01

    Full Text Available The methanogenic biodegradation of crude oil is an important process occurring in petroleum reservoirs and other oil-containing environments such as contaminated aquifers. In this process, syntrophic bacteria degrade hydrocarbon substrates to products such as acetate, and/or H2 and CO2 that are then used by methanogens to produce methane in a thermodynamically dependent manner. We enriched a methanogenic crude oil-degrading consortium from production waters sampled from a low temperature heavy oil reservoir. Alkylsuccinates indicative of fumarate addition to C5 and C6 n-alkanes were identified in the culture (above levels found in controls, corresponding to the detection of an alkyl succinate synthase gene (assA in the culture. In addition, the enrichment culture was tested for its ability to produce methane from residual oil in a sandstone-packed column system simulating a mature field. Methane production rates of up 5.8 μmol CH4/g of oil/day were measured in the column system. Amounts of produced methane were in relatively good agreement with hydrocarbon loss showing depletion of more than 50% of saturate and aromatic hydrocarbons. Microbial community analysis revealed that the enrichment culture was dominated by members of the genus Smithella, Methanosaeta, and Methanoculleus. However, a shift in microbial community occurred following incubation of the enrichment in the sandstone columns. Here, Methanobacterium sp. were most abundant, as were bacterial members of the genus Pseudomonas and other known biofilm forming organisms. Our findings show that microorganisms enriched from petroleum reservoir waters can bioconvert crude oil components to methane both planktonically and in sandstone-packed columns as test systems. Further, the results suggest that different organisms may contribute to oil biodegradation within different phases (e.g., planktonic versus sessile within a subsurface crude oil reservoir.

  4. Enhanced oil recovery methods studied by gamma tracer scanning at simulated reservoir conditions

    International Nuclear Information System (INIS)

    Eriksen, D.O.; Haugen, O.B.; Bjornstad, T.

    2009-01-01

    During recovery (production) of hydrocarbons pressure is maintained by injecting prepared sea water and recycled gas (lean gas) into dedicated injection wells. In one well at the Snorre field in the North Sea the injected gas was recycled too fast to enable support of pressure and squeezing of oil. To plug this high-permeable area the operator wanted to inject foam as a test of its possibilities to decrease gas permeability. As part of the project laboratory tests were included. In these tests we could for the first time map the foam inside the sandstone sample at simulated reservoir conditions. The tracers used were 22 Na + for the γ-scanning of the aqueous brine, tritiated water for permeability measurements, and 35 S-labeled organic sulfonic acid of the same compound as the surfactant. This method resulted in a 'negative' mapping of the foam, i.e. measurements of the absence or exclusion of the aqueous phase by the foam. This method was new and showed that radiotracer-based γ-scanning could give much more accurate measurements of the position of the foam than the standard method using measurements of pressure drops over parts of the core. (author)

  5. Origin of late pleistocene formation water in Mexican oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Birkle, P. [Instituto de Investigaciones Electricas, Cuernavaca (Mexico)

    2004-07-01

    Brine water invasion into petroleum reservoirs, especially in sedimentary basins, are known from a variety of global oil field, such as the Western Canada sedimentary basin and, the central Mississippi Salt Dome basin (Kharaka et al., 1987). The majority of oil wells, especially in the more mature North American fields, produce more water than they do oil (Peachey et al., 1998). In the case of Mexican oil fields, increasing volumes of invading water into the petroleum wells were detected during the past few years. Major oil reserves in the SE-part of the Gulf of Mexico are economically affected due to decreases in production rate, pipeline corrosion and well closure. The origin of deep formation water in many sedimentary basins is still controversial: Former hypothesis mainly in the 60's, explained the formation of formation water by entrapment of seawater during sediment deposition. Subsequent water-rock interaction processes explain the chemical evolution of hydrostatic connate water. More recent hydrodynamic models, mainly based on isotopic data, suggest the partial migration of connate fluids, whereas the subsequent invasion of surface water causes mixing processes (Carpenter 1978). As part of the presented study, a total of 90 oil production wells were sampled from 1998 to 2004 to obtain chemical (Major and trace elements) and isotopic composition ({sup 2}H, {sup 13}C, {sup 14}C, {sup 18}O {sup 36}Cl, {sup 37}Cl, {sup 87}Sr, {sup 129}I, tritium) of deep formation water at the Mexican Gulf coast. Samples were extracted from carbonate-type reservoirs of the oil fields Luna, Samaria-Sitio Grande, Jujo-Tecominoac (on-shore), and Pol-Chuc (off-shore, including Abkatun, Batab, Caan, and Taratunich) at a depth between 2,900 m b.s.l. and 6,100 m b.s.l. During the field work, the influence of atmospheric contamination e.g. by CO{sub 2}-atmospheric input was avoided by using an interval sampler to get in-situ samples from the extraction zone of selected bore holes

  6. Injection of multi-azimuth permeable planes in weakly cemented formations for enhanced heavy-oil recovery

    Energy Technology Data Exchange (ETDEWEB)

    Hocking, G. [Society of Petroleum Engineers, Richardson, TX (United States)]|[GeoSierra LLC, Norcross, GA (United States); Cavender, T.; Schultz, R.L. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[Halliburton Energy Services, Calgary, AB (Canada)

    2008-10-15

    Weakly cemented formations have minimal strength without fracture toughness. As such, the well stimulation process must be different from the fracturing process that occurs in hard rocks. This paper presented field injection experiments of multi-azimuth, injected, vertical planar geometries in several weakly cemented formations. The application of the method to shallow petroleum soft rock reservoirs was described, with particular reference to the thermal and solvent recovery of heavy oil. This study showed that in weakly cemented formations, a well-initiation device can control the azimuth of injected vertical planes, thereby controlling the rate of injection and the viscosity of the injected fluid. The concept of using the multi-azimuth, vertical permeable planes has strong potential in soft-rock formations for enhanced production in both shallow gas and shallow heavy-oil reservoirs. The method can be applied in a single well injector-producer for the continuous injection of steam and the continuous extraction of oil, similar to steam assisted gravity drainage (SAGD) and may be more efficient than a confined horizontal well pair typically used in SAGD. However, the authors noted that the effectiveness of the multi-azimuth process has yet to be proven for oil sand formations. 13 refs., 1 tab., 13 figs.

  7. Maximize Liquid Oil Production from Shale Oil and Gas Condensate Reservoirs by Cyclic Gas Injection

    Energy Technology Data Exchange (ETDEWEB)

    Sheng, James [Texas Tech Univ., Lubbock, TX (United States); Li, Lei [Texas Tech Univ., Lubbock, TX (United States); Yu, Yang [Texas Tech Univ., Lubbock, TX (United States); Meng, Xingbang [Texas Tech Univ., Lubbock, TX (United States); Sharma, Sharanya [Texas Tech Univ., Lubbock, TX (United States); Huang, Siyuan [Texas Tech Univ., Lubbock, TX (United States); Shen, Ziqi [Texas Tech Univ., Lubbock, TX (United States); Zhang, Yao [Texas Tech Univ., Lubbock, TX (United States); Wang, Xiukun [Texas Tech Univ., Lubbock, TX (United States); Carey, Bill [Los Alamos National Lab. (LANL), Los Alamos, NM (United States); Nguyen, Phong [Los Alamos National Lab. (LANL), Los Alamos, NM (United States); Porter, Mark [Los Alamos National Lab. (LANL), Los Alamos, NM (United States); Jimenez-Martinez, Joaquin [Los Alamos National Lab. (LANL), Los Alamos, NM (United States); Viswanathan, Hari [Los Alamos National Lab. (LANL), Los Alamos, NM (United States); Mody, Fersheed [Apache Corp., Houston, TX (United States); Barnes, Warren [Apache Corp., Houston, TX (United States); Cook, Tim [Apache Corp., Houston, TX (United States); Griffith, Paul [Apache Corp., Houston, TX (United States)

    2017-11-17

    The current technology to produce shale oil reservoirs is the primary depletion using fractured wells (generally horizontal wells). The oil recovery is less than 10%. The prize to enhance oil recovery (EOR) is big. Based on our earlier simulation study, huff-n-puff gas injection has the highest EOR potential. This project was to explore the potential extensively and from broader aspects. The huff-n-puff gas injection was compared with gas flooding, water huff-n-puff and waterflooding. The potential to mitigate liquid blockage was also studied and the gas huff-n-puff method was compared with other solvent methods. Field pilot tests were initiated but terminated owing to the low oil price and the operator’s budget cut. To meet the original project objectives, efforts were made to review existing and relevant field projects in shale and tight reservoirs. The fundamental flow in nanopores was also studied.

  8. Vascular permeability-increasing effect of the leaf essential oil of ...

    African Journals Online (AJOL)

    African Journal of Traditional, Complementary and Alternative Medicines ... Analysis of the differences in vascular permeability between treatment groups showed that, Ocimum oil, in intensity and duration, was significantly (p < 0.05) more effective in increasing cutaneous capillary permeability over a 24h period after ...

  9. Simulation study of huff-n-puff air injection for enhanced oil recovery in shale oil reservoirs

    Directory of Open Access Journals (Sweden)

    Hu Jia

    2018-03-01

    Full Text Available This paper is the first attempt to evaluate huff-n-puff air injection in a shale oil reservoir using a simulation approach. Recovery mechanisms and physical processes of huff-n-puff air injection in a shale oil reservoir are investigated through investigating production performance, thermal behavior, reservoir pressure and fluid saturation features. Air flooding is used as the basic case for a comparative study. The simulation study suggests that thermal drive is the main recovery mechanism for huff-n-puff air injection in the shale oil reservoir, but not for simple air flooding. The synergic recovery mechanism of air flooding in conventional light oil reservoirs can be replicated in shale oil reservoirs by using air huff-n-puff injection strategy. Reducing huff-n-puff time is better for performing the synergic recovery mechanism of air injection. O2 diffusion plays an important role in huff-n-puff air injection in shale oil reservoirs. Pressure transmissibility as well as reservoir pressure maintenance ability in huff-n-puff air injection is more pronounced than the simple air flooding after primary depletion stage. No obvious gas override is exhibited in both air flooding and air huff-n-puff injection scenarios in shale reservoirs. Huff-n-puff air injection has great potential to develop shale oil reservoirs. The results from this work may stimulate further investigations.

  10. GPU-Based Computation of Formation Pressure for Multistage Hydraulically Fractured Horizontal Wells in Tight Oil and Gas Reservoirs

    Directory of Open Access Journals (Sweden)

    Rongwang Yin

    2018-01-01

    Full Text Available A mathematical model for multistage hydraulically fractured horizontal wells (MFHWs in tight oil and gas reservoirs was derived by considering the variations in the permeability and porosity of tight oil and gas reservoirs that depend on formation pressure and mixed fluid properties and introducing the pseudo-pressure; analytical solutions were presented using the Newman superposition principle. The CPU-GPU asynchronous computing model was designed based on the CUDA platform, and the analytic solution was decomposed into infinite summation and integral forms for parallel computation. Implementation of this algorithm on an Intel i5 4590 CPU and NVIDIA GT 730 GPU demonstrates that computation speed increased by almost 80 times, which meets the requirement for real-time calculation of the formation pressure of MFHWs.

  11. Multigrid methods for fully implicit oil reservoir simulation

    Energy Technology Data Exchange (ETDEWEB)

    Molenaar, J.

    1995-12-31

    In this paper, the authors consider the simultaneous flow of oil and water in reservoir rock. This displacement process is modeled by two basic equations the material balance or continuity equations, and the equation of motion (Darcy`s law). For the numerical solution of this system of nonlinear partial differential equations, there are two approaches: the fully implicit or simultaneous solution method, and the sequential solution method. In this paper, the authors consider the possibility of applying multigrid methods for the iterative solution of the systems of nonlinear equations.

  12. Reservoir characterization and monitoring of cold and thermal heavy oil production using multi-transient EM

    Energy Technology Data Exchange (ETDEWEB)

    Engelmark, F. [Petroleum Geo-Services Asia Pacific Pte Ltd., Singapore (Singapore)

    2008-10-15

    This study emphasized the importance of mapping the in situ subsurface distribution of heavy oil for evaluating the amount of oil in place. The multi-transient electromagnetic (MTEM) method was shown to be an ideal method to characterize the large scale distribution of oil, including the average saturation levels, on the scale needed to optimize oil extraction using steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). A feasibility study for an MTEM monitoring project would simulate reservoir temperature, water saturation and salinity to determine the evolution over time expressed in resistivity and the expanding steam chamber. The 4 factors influencing the resistivity in the monitoring phase were discussed. The temperature due to steaming causes a significant drop in resistivity of the affected rock volume, while the changes in water saturation affect resistivity. The drop in salinity of the pore water due to mixing with distilled water originating in the condensation of the injected steam causes an increase in resistivity, while the mineral dissolution and overall volume expansion causes formation damage that permanently changes the rock fabric. The overall effect of steam injection is a reduction in resistivity within the main part of the chamber, with a sudden increase in resistivity in the proximity of the injection well due to salt depletion. The lowered resistivity within a halo outside the steam chamber can be attributed to the heat radiation front expanding faster than the maturing steam chamber. The author noted that reservoir simulators do not yet incorporate the dynamic changes in porosity and permeability that are observed as permanent reductions of the elastic moduli and reduced resistivity. It was concluded that in order to fully describe the evolution of the steam chamber, this so called formation damage must be better understood. 6 refs., 7 figs.

  13. Potential evaluation of CO2 storage and enhanced oil recovery of tight oil reservoir in the Ordos Basin, China.

    Science.gov (United States)

    Tian, Xiaofeng; Cheng, Linsong; Cao, Renyi; Zhang, Miaoyi; Guo, Qiang; Wang, Yimin; Zhang, Jian; Cui, Yu

    2015-07-01

    Carbon -di-oxide (CO2) is regarded as the most important greenhouse gas to accelerate climate change and ocean acidification. The Chinese government is seeking methods to reduce anthropogenic CO2 gas emission. CO2 capture and geological storage is one of the main methods. In addition, injecting CO2 is also an effective method to replenish formation energy in developing tight oil reservoirs. However, exiting methods to estimate CO2 storage capacity are all based on the material balance theory. This was absolutely correct for normal reservoirs. However, as natural fractures widely exist in tight oil reservoirs and majority of them are vertical ones, tight oil reservoirs are not close. Therefore, material balance theory is not adaptive. In the present study, a new method to calculate CO2 storage capacity is presented. The CO2 effective storage capacity, in this new method, consisted of free CO2, CO2 dissolved in oil and CO2 dissolved in water. Case studies of tight oil reservoir from Ordos Basin was conducted and it was found that due to far lower viscosity of CO2 and larger solubility in oil, CO2 could flow in tight oil reservoirs more easily. As a result, injecting CO2 in tight oil reservoirs could obviously enhance sweep efficiency by 24.5% and oil recovery efficiency by 7.5%. CO2 effective storage capacity of Chang 7 tight oil reservoir in Longdong area was 1.88 x 10(7) t. The Chang 7 tight oil reservoir in Ordos Basin was estimated to be 6.38 x 10(11) t. As tight oil reservoirs were widely distributed in Songliao Basin, Sichuan Basin and so on, geological storage capacity of CO2 in China is potential.

  14. Prediction of Geomechanical Properties from Thermal Conductivity of Low-Permeable Reservoirs

    Science.gov (United States)

    Chekhonin, Evgeny; Popov, Evgeny; Popov, Yury; Spasennykh, Mikhail; Ovcharenko, Yury; Zhukov, Vladislav; Martemyanov, Andrey

    2016-04-01

    A key to assessing a sedimentary basin's hydrocarbon prospect is correct reconstruction of thermal and structural evolution. It is impossible without adequate theory and reliable input data including among other factors thermal and geomechanical rock properties. Both these factors are also important in geothermal reservoirs evaluation and carbon sequestration problem. Geomechanical parameters are usually estimated from sonic logging and rare laboratory measurements, but sometimes it is not possible technically (low quality of the acoustic signal, inappropriate borehole and mud conditions, low core quality). No wonder that there are attempts to correlate the thermal and geomechanical properties of rock, but no one before did it with large amount of high quality thermal conductivity data. Coupling results of sonic logging and non-destructive non-contact thermal core logging opens wide perspectives for studying a relationship between the thermal and geomechanical properties. More than 150 m of full size cores have been measured at core storage with optical scanning technique. Along with results of sonic logging performed with Sonic Scanner in different wells drilled in low permeable formations in West Siberia (Russia) it provided us with unique data set. It was established a strong correlation between components of thermal conductivity (measured perpendicular and parallel to bedding) and compressional and shear acoustic velocities in Bazhen formation. As a result, prediction of geomechanical properties via thermal conductivity data becomes possible, corresponding results was demonstrated. The work was supported by the Russian Ministry of Education and Science, project No. RFMEFI58114X0008.

  15. INCREASED OIL PRODUCTION AND RESERVES UTILIZING SECONDARY/TERTIARY RECOVERY TECHNIQUES ON SMALL RESERVOIRS IN THE PARADOX BASIN, UTAH

    Energy Technology Data Exchange (ETDEWEB)

    Thomas C. Chidsey, Jr.

    2002-11-01

    The Paradox Basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from shallow-shelf carbonate buildups or mounds within the Desert Creek zone of the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels (111,300-318,000 m{sup 3}) of oil per field at a 15 to 20 percent recovery rate. Five fields in southeastern Utah were evaluated for waterflood or carbon-dioxide (CO{sub 2})-miscible flood projects based upon geological characterization and reservoir modeling. Geological characterization on a local scale focused on reservoir heterogeneity, quality, and lateral continuity as well as possible compartmentalization within each of the five project fields. The Desert Creek zone includes three generalized facies belts: (1) open-marine, (2) shallow-shelf and shelf-margin, and (3) intra-shelf, salinity-restricted facies. These deposits have modern analogs near the coasts of the Bahamas, Florida, and Australia, respectively, and outcrop analogs along the San Juan River of southeastern Utah. The analogs display reservoir heterogeneity, flow barriers and baffles, and lithofacies geometry observed in the fields; thus, these properties were incorporated in the reservoir simulation models. Productive carbonate buildups consist of three types: (1) phylloid algal, (2) coralline algal, and (3) bryozoan. Phylloid-algal buildups have a mound-core interval and a supra-mound interval. Hydrocarbons are stratigraphically trapped in porous and permeable lithotypes within the mound-core intervals of the lower part of the buildups and the more heterogeneous supramound intervals. To adequately represent the observed spatial heterogeneities in reservoir properties, the phylloid-algal bafflestones of the mound-core interval and the dolomites of the overlying supra-mound interval were subdivided into ten architecturally distinct lithotypes, each of which

  16. Modeling of CO2 migration injected in Weyburn oil reservoir

    International Nuclear Information System (INIS)

    Zhou Wei; Stenhouse, M.J.; Arthur, R.

    2008-01-01

    Injecting CO 2 into oil and gas field is a way to enhance oil recovery (EOR) as well as mitigate global warming effect by permanently storing the greenhouse gas into underground. This paper details the models and results of simulating the long-term migration of CO 2 injected into the Weyburn field for both Enhanced Oil Recovery operations and CO 2 sequestration. A System Model was established to define the spatial and temporal extents of the analysis. The Base Scenario was developed to identify key processes, features, and events (FEPs) for the expected evolution of the storage system. A compositional reservoir simulator with equations-of-states (EOS) was used as the modeling tool in order to simulate multiphase, multi-component flow and transport coupled with CO 2 mass partitioning into oil, gas, and water phases. We apply a deterministic treatment to CO 2 migration in the geosphere (natural pathways), whereas the variability of abandoned wells (man-made pathways) necessitates a stochastic treatment. The simulation result was then used to carry out consequence analysis to the local environment. (authors)

  17. Enhanced oil recovery by nitrogen and carbon dioxide injection followed by low salinity water flooding for tight carbonate reservoir: experimental approach

    Science.gov (United States)

    Georges Lwisa, Essa; Abdulkhalek, Ashrakat R.

    2018-03-01

    Enhanced Oil Recovery techniques are one of the top priorities of technology development in petroleum industries nowadays due to the increase in demand for oil and gas which cannot be equalized by the primary production or secondary production methods. The main function of EOR process is to displace oil to the production wells by the injection of different fluids to supplement the natural energy present in the reservoir. Moreover, these injecting fluids can also help in the alterations of the properties of the reservoir like lowering the IFTs, wettability alteration, a change in pH value, emulsion formation, clay migration and oil viscosity reduction. The objective of this experiment is to investigate the residual oil recovery by combining the effects of gas injection followed by low salinity water injection for low permeability reservoirs. This is done by a series of flooding tests on selected tight carbonate core samples taken from Zakuum oil field in Abu Dhabi by using firstly low salinity water as the base case and nitrogen & CO2injection followed by low salinity water flooding at reservoir conditions of pressure and temperature. The experimental results revealed that a significant improvement of the oil recovery is achieved by the nitrogen injection followed by the low salinity water flooding with a recovery factor of approximately 24% of the residual oil.

  18. Influence of infiltrated water on the change of formation water and oil permeability of crude oil bearing rocks

    Energy Technology Data Exchange (ETDEWEB)

    Cubric, S

    1970-09-01

    A brief desription is given of the causes of permeability reduction of oil-bearing rocks, due to well damage during the drilling and well completion or when working over wells. The physical properties of 2-phase flow (crude oil-water) and the possibility of increasing the existing permeability of the formation, because of the water infiltrated from the well into the crude oil layer, are described in detail. Field examples show that there are such cases, and that the artificially increased existing permeability of water-bearing rocks can be reduced and even brought to normal, if the adjacent formation zone layer is treated with surfactants (e.g., Hyflo dissolved in crude oil).

  19. Integrating gravimetric and interferometric synthetic aperture radar data for enhancing reservoir history matching of carbonate gas and volatile oil reservoirs

    KAUST Repository

    Katterbauer, Klemens

    2016-08-25

    Reservoir history matching is assuming a critical role in understanding reservoir characteristics, tracking water fronts, and forecasting production. While production data have been incorporated for matching reservoir production levels and estimating critical reservoir parameters, the sparse spatial nature of this dataset limits the efficiency of the history matching process. Recently, gravimetry techniques have significantly advanced to the point of providing measurement accuracy in the microgal range and consequently can be used for the tracking of gas displacement caused by water influx. While gravity measurements provide information on subsurface density changes, i.e., the composition of the reservoir, these data do only yield marginal information about temporal displacements of oil and inflowing water. We propose to complement gravimetric data with interferometric synthetic aperture radar surface deformation data to exploit the strong pressure deformation relationship for enhancing fluid flow direction forecasts. We have developed an ensemble Kalman-filter-based history matching framework for gas, gas condensate, and volatile oil reservoirs, which synergizes time-lapse gravity and interferometric synthetic aperture radar data for improved reservoir management and reservoir forecasts. Based on a dual state-parameter estimation algorithm separating the estimation of static reservoir parameters from the dynamic reservoir parameters, our numerical experiments demonstrate that history matching gravity measurements allow monitoring the density changes caused by oil-gas phase transition and water influx to determine the saturation levels, whereas the interferometric synthetic aperture radar measurements help to improve the forecasts of hydrocarbon production and water displacement directions. The reservoir estimates resulting from the dual filtering scheme are on average 20%-40% better than those from the joint estimation scheme, but require about a 30% increase in

  20. Experimental study of heavy oil-water flow structure effects on relative permeabilities in a fracture filled with heavy oil

    Energy Technology Data Exchange (ETDEWEB)

    Shad, S.; Gates, I.D.; Maini, B.B. [Calgary Univ., AB (Canada). Dept. of Chemical and Petroleum Engineering]|[Alberta Ingenuity Centre for In Situ Energy, Edmonton, AB (Canada)

    2008-10-15

    An experimental apparatus was used to investigate the flow of water in the presence of heavy oil within a smooth-walled fracture. Different flow patterns were investigated under a variety of flow conditions. Results of the experiments were used to determine the accuracy of VC, Corey, and Shad and Gates models designed to represent the behaviour of oil wet systems. The relative permeability concept was used to describe the behaviour of multiple phases flowing through porous media. A smooth-walled plexiglass Hele-Shaw cell was used to visualize oil and water flow. Changes in flow rates led to different flow regimes. The experiment demonstrated that water flowed co-currently in the form of droplets or slugs. Decreases in the oil flow rate enlarged the size of the water droplets as well as the velocity, until eventually the droplets coalesced and became water slugs. Droplet appearance or disappearance directly impacted the oil and water saturation levels. Changes in fluid saturation altered the pressure gradient. Darcy's law for the 2 liquid phases were used to calculate relative permeability curves. The study showed that at low water saturation, oil relative permeability reached as high as 2.5, while water relative permeability was lower than unity. In the presence of a continuous water channel, water drops formed in oil, and the velocity of the drops was lower than their velocity under a discontinuous water flow regime. It was concluded that the Shad and Gates model overestimated oil relative permeability and underestimated water relative permeability. 38 refs., 2 tabs., 9 figs.

  1. Estimation of Oil Production Rates in Reservoirs Exposed to Focused Vibrational Energy

    KAUST Repository

    Jeong, Chanseok; Kallivokas, Loukas F.; Huh, Chun; Lake, Larry W.

    2014-01-01

    the production rate of remaining oil from existing oil fields. To date, there are few theoretical studies on estimating how much bypassed oil within an oil reservoir could be mobilized by such vibrational stimulation. To fill this gap, this paper presents a

  2. CHARACTERIZATION OF IN-SITU STRESS AND PERMEABILITY IN FRACTURED RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Daniel R. Burns; M. Nafi Toksoz

    2004-07-19

    Expanded details and additional results are presented on two methods for estimating fracture orientation and density in subsurface reservoirs from scattered seismic wavefield signals. In the first, fracture density is estimated from the wavenumber spectra of the integrated amplitudes of the scattered waves as a function of offset in pre-stack data. Spectral peaks correctly identified the 50m, 35m, and 25m fracture spacings from numerical model data using a 40Hz source wavelet. The second method, referred to as the Transfer Function-Scattering Index Method, is based upon observations from 3D finite difference modeling that regularly spaced, discrete vertical fractures impart a ringing coda-type signature to any seismic energy that is transmitted through or reflected off of them. This coda energy is greatest when the acquisition direction is parallel to the fractures, the seismic wavelengths are tuned to the fracture spacing, and when the fractures have low stiffness. The method uses surface seismic reflection traces to derive a transfer function, which quantifies the change in an apparent source wavelet propagating through a fractured interval. The transfer function for an interval with low scattering will be more spike-like and temporally compact. The transfer function for an interval with high scattering will ring and be less temporally compact. A Scattering Index is developed based on a time lag weighting of the transfer function. When a 3D survey is acquired with a full range of azimuths, the Scattering Index allows the identification of subsurface areas with high fracturing and the orientation (or strike) of those fractures. The method was calibrated with model data and then applied to field data from a fractured reservoir giving results that agree with known field measurements. As an aid to understanding the scattered wavefield seen in finite difference models, a series of simple point scatterers was used to create synthetic seismic shot records collected over

  3. Pore Structure and Diagenetic Controls on Relative Permeability: Implications for Enhanced Oil Recovery and CO2 Storage

    Science.gov (United States)

    Feldman, J.; Dewers, T. A.; Heath, J. E.; Cather, M.; Mozley, P.

    2016-12-01

    Multiphase flow in clay-bearing sandstones of the Morrow Sandstone governs the efficiency of CO2 storage and enhanced oil recovery at the Farnsworth Unit, Texas. This formation is the target for enhanced oil recovery and injection of one million metric ton of anthropogenically-sourced CO2. The sandstone hosts eight major flow units that exhibit distinct microstructural characteristics due to diagenesis, including: "clean" macro-porosity; quartz overgrowths constricting some pores; ghost grains; intergranular porosity filled by microporous authigenic clay; and feldspar dissolution. We examine the microstructural controls on macroscale (core scale) relative permeability and capillary pressure behavior through: X-ray computed tomography, Robomet.3d, and focused ion beam-scanning electron microscopy imaging of the pore structure of the major flow units of the Morrow Sandstone; relative permeability and capillary pressure in the laboratory using CO2, brine, and oil at reservoir pressure and effective stress conditions. The combined data sets inform links between patterns of diagenesis and multiphase flow. These data support multiphase reservoir simulation and performance assessment by the Southwest Regional Partnership on Carbon Sequestration (SWP). Funding for this project is provided by the U.S. Department of Energy's National Energy Technology Laboratory through the SWP under Award No. DE-FC26-05NT42591. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

  4. Application of microbiological methods for secondary oil recovery from the Carpathian crude oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Karaskiewicz, J

    1974-01-01

    The investigation made it possible to isolate from different ecologic environmental (soil, crude oil, formation water, industrial wastes) bacteria cultures of the genus Arthrobacter, Clostridium, Mycobacterium, Peptococcus, and Pseudomonas. These heterotrophic bacteria are characterized by a high metabolic and biogeochemical activity hydrocarbon transformation. Experiments on a technical scale were conducted from 1961 to 1971 in 20 wells; in this study, only the 16 most typical examples are discussed. The experiments were conducted in Carpathian crude oil reservoirs. To each well, a 500:1 mixture of the so-called bacteria vaccine (containing an active biomass of cultures obtained by a specific cultivation method and holding 6 x 10/sup 5/ bacteria cells in 1 ml of fluid, 2,000 kg of molasses, and 50 cu m of water originating from the reservoir submitted to treatment) was injected at 500 to 1,200 m. The intensification of the microbiological processes in the reservoir was observed. This phenomenon occurred not only in the wells to which the bacteria vaccine was injected, but also in the surrounding producing wells. At the same time, an increase in the crude oil production occurred on the average within the range from 20 to 200% and the surpluses of crude oil production continued for 2 to 8 yr. (92 refs.)

  5. Lessons learned from IOR steamflooding in a bitumen-light oil heterogeneous reservoir

    NARCIS (Netherlands)

    Al Mudhafar, W.J.M.; Hosseini Nasab, S.M.

    2015-01-01

    The Steamflooding was considered in this research to extract the discontinuous bitumen layers that are located at the oil-water contact for the heterogeneous light oil sandstone reservoir of South Rumaila Field. The reservoir heterogeneity and the bitumen layers impede water aquifer approaching into

  6. On the feasibility of inducing oil mobilization in existing reservoirs via wellbore harmonic fluid action

    KAUST Repository

    Jeong, Chanseok; Huh, Chun; Kallivokas, Loukas F.

    2011-01-01

    Although vibration-based mobilization of oil remaining in mature reservoirs is a promising low-cost method of enhanced oil recovery (EOR), research on its applicability at the reservoir scale is still at an early stage. In this paper, we use

  7. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies, Class III

    Energy Technology Data Exchange (ETDEWEB)

    City of Long Beach; Tidelands Oil Production Company; University of Southern California; David K. Davies and Associates

    2002-09-30

    The objective of this project was to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. It was hoped that the successful application of these technologies would result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs.

  8. Damage evaluation on oil-based drill-in fluids for ultra-deep fractured tight sandstone gas reservoirs

    Directory of Open Access Journals (Sweden)

    Jinzhi Zhu

    2017-07-01

    Full Text Available In order to explore the damage mechanisms and improve the method to evaluate and optimize the performance of formation damage control of oil-based drill-in fluids, this paper took an ultra-deep fractured tight gas reservoir in piedmont configuration, located in the Cretaceous Bashijiqike Fm of the Tarim Basin, as an example. First, evaluation experiments were conducted on the filtrate invasion, the dynamic damage of oil-based drill-in fluids and the loading capacity of filter cakes. Meanwhile, the evaluating methods were optimized for the formation damage control effect of oil-based drill-in fluids in laboratory: pre-processing drill-in fluids before grading analysis; using the dynamic damage method to simulate the damage process for evaluating the percentage of regained permeability; and evaluating the loading capacity of filter cakes. The experimental results show that (1 oil phase trapping damage and solid phase invasion are the main formation damage types; (2 the damage degree of filtrate is the strongest on the matrix; and (3 the dynamic damage degree of oil-based drill-in fluids reaches medium strong to strong on fractures and filter cakes show a good sealing capacity for the fractures less than 100 μm. In conclusion, the filter cakes' loading capacity should be first guaranteed, and both percentage of regained permeability and liquid trapping damage degree should be both considered in the oil-based drill-in fluids prepared for those ultra-deep fractured tight sandstone gas reservoirs.

  9. Research on removing reservoir core water sensitivity using the method of ultrasound-chemical agent for enhanced oil recovery.

    Science.gov (United States)

    Wang, Zhenjun; Huang, Jiehao

    2018-04-01

    The phenomenon of water sensitivity often occurs in the oil reservoir core during the process of crude oil production, which seriously affects the efficiency of oil extraction. In recent years, near-well ultrasonic processing technology attaches more attention due to its safety and energy efficient. In this paper, the comparison of removing core water sensitivity by ultrasonic wave, chemical injection and ultrasound-chemical combination technique are investigated through experiments. Results show that: lower ultrasonic frequency and higher power can improve the efficiency of core water sensitivity removal; the effects of removing core water sensitivity under ultrasonic treatment get better with increase of core initial permeability; the effect of removing core water sensitivity using ultrasonic treatment won't get better over time. Ultrasonic treatment time should be controlled in a reasonable range; the effect of removing core water sensitivity using chemical agent alone is slightly better than that using ultrasonic treatment, however, chemical injection could be replaced by ultrasonic treatment for removing core water sensitivity from the viewpoint of oil reservoir protection and the sustainable development of oil field; ultrasound-chemical combination technique has the best effect for water sensitivity removal than using ultrasonic treatment or chemical injection alone. Copyright © 2017 Elsevier B.V. All rights reserved.

  10. Low-frequency ESR studies on permeable and impermeable deuterated nitroxyl radicals in corn oil solution.

    Science.gov (United States)

    David Jebaraj, D; Utsumi, Hideo; Milton Franklin Benial, A

    2018-04-01

    Low-frequency electron spin resonance studies were performed for 2 mM concentration of deuterated permeable and impermeable nitroxyl spin probes, 3-methoxycarbonyl-2,2,5,5-tetramethyl-pyrrolidine-1-oxyl and 3-carboxy-2,2,5,5,-tetramethyl-1-pyrrolidinyloxy in pure water and various concentrations of corn oil solution. The electron spin resonance parameters such as the line width, hyperfine coupling constant, g factor, rotational correlation time, permeability, and partition parameter were estimated. The broadening of line width was observed for nitroxyl radicals in corn oil mixture. The rotational correlation time increases with increasing concentration of corn oil, which indicates the less mobile nature of spin probe in corn oil mixture. The membrane permeability and partition parameter values were estimated as a function of corn oil concentration, which reveals that the nitroxyl radicals permeate equally into the aqueous phase and oil phase at the corn oil concentration of 50%. The electron spin resonance spectra demonstrate the permeable and impermeable nature of nitroxyl spin probes. From these results, the corn oil concentration was optimized as 50% for phantom studies. In this work, the corn oil and pure water mixture phantom models with various viscosities correspond to plasma membrane, and whole blood membrane with different hematocrit levels was studied for monitoring the biological characteristics and their interactions with permeable nitroxyl spin probe. These results will be useful for the development of electron spin resonance and Overhauser-enhanced magnetic resonance imaging modalities in biomedical applications. Copyright © 2017 John Wiley & Sons, Ltd.

  11. Elastic-Brittle-Plastic Behaviour of Shale Reservoirs and Its Implications on Fracture Permeability Variation: An Analytical Approach

    Science.gov (United States)

    Masoudian, Mohsen S.; Hashemi, Mir Amid; Tasalloti, Ali; Marshall, Alec M.

    2018-05-01

    Shale gas has recently gained significant attention as one of the most important unconventional gas resources. Shales are fine-grained rocks formed from the compaction of silt- and clay-sized particles and are characterised by their fissured texture and very low permeability. Gas exists in an adsorbed state on the surface of the organic content of the rock and is freely available within the primary and secondary porosity. Geomechanical studies have indicated that, depending on the clay content of the rock, shales can exhibit a brittle failure mechanism. Brittle failure leads to the reduced strength of the plastic zone around a wellbore, which can potentially result in wellbore instability problems. Desorption of gas during production can cause shrinkage of the organic content of the rock. This becomes more important when considering the use of shales for CO2 sequestration purposes, where CO2 adsorption-induced swelling can play an important role. These phenomena lead to changes in the stress state within the rock mass, which then influence the permeability of the reservoir. Thus, rigorous simulation of material failure within coupled hydro-mechanical analyses is needed to achieve a more systematic and accurate representation of the wellbore. Despite numerous modelling efforts related to permeability, an adequate representation of the geomechanical behaviour of shale and its impact on permeability and gas production has not been achieved. In order to achieve this aim, novel coupled poro-elastoplastic analytical solutions are developed in this paper which take into account the sorption-induced swelling and the brittle failure mechanism. These models employ linear elasticity and a Mohr-Coulomb failure criterion in a plane-strain condition with boundary conditions corresponding to both open-hole and cased-hole completions. The post-failure brittle behaviour of the rock is defined using residual strength parameters and a non-associated flow rule. Swelling and shrinkage

  12. Simulation study of the VAPEX process in fractured heavy oil system at reservoir conditions

    Energy Technology Data Exchange (ETDEWEB)

    Azin, Reza; Ghotbi, Cyrus [Department of Chemical and Petroleum Engineering, Sharif Univ. Tech., Tehran (Iran); Kharrat, Riyaz; Rostami, Behzad [Petroleum University of Technology Research Center, Tehran (Iran); Vossoughi, Shapour [4132C Learned Hall, Department of Chemical and Petroleum Engineering, Kansas University, Lawrence, KS (United States)

    2008-01-15

    The Vapor Extraction (VAPEX) process, a newly developed Enhanced Oil Recovery (EOR) process to recover heavy oil and bitumen, has been studied theoretically and experimentally and is found a promising EOR method for certain heavy oil reservoirs. In this work, a simulation study of the VAPEX process was made on a fractured model, which consists of a matrix surrounded by horizontal and vertical fractures. The results show a very interesting difference in the pattern of solvent flow in fractured model compared with the conventional model. Also, in the fractured system, due to differences in matrix and fracture permeabilities, the solvent first spreads through the fractures and then starts diffusing into matrix from all parts of the matrix. Thus, the solvent surrounds the oil bank, and an oil rather than the solvent chamber forms and shrinks as the process proceeds. In addition, the recovery factor is higher at lower solvent injection rates for a constant pore volume of the solvent injected into the model. Also, the diffusion process becomes important and higher recoveries are obtained at low injection rates, provided sufficient time is given to the process. The effect of inter-connectivity of the surrounding fractures was studied by making the side vertical fractures shorter than the side length of the model. It was observed that inter-connectivity of the fractures affects the pattern of solvent distribution. Even for the case of side fractures being far apart from the bottom fracture, the solvent distribution in the matrix was significantly different than that in the model without fractures. Combination of diffusion phenomenon and gravity segregation was observed to be controlling factors in all VAPEX processes simulated in fractured systems. The early breakthrough of the solvent for the case of matrix surrounded by the fracture partially inhibited diffusion of the solvent into the oil and consequently the VAPEX process became the least effective. It is concluded

  13. 3-D RESERVOIR AND STOCHASTIC FRACTURE NETWORK MODELING FOR ENHANCED OIL RECOVERY, CIRCLE RIDGE PHOSPHORIA/TENSLEEP RESERVOIR, WIND RIVER RESERVATION, ARAPAHO AND SHOSHONE TRIBES, WYOMING

    Energy Technology Data Exchange (ETDEWEB)

    Paul La Pointe; Jan Hermanson; Robert Parney; Thorsten Eiben; Mike Dunleavy; Ken Steele; John Whitney; Darrell Eubanks; Roger Straub

    2002-11-18

    This report describes the results made in fulfillment of contract DE-FG26-00BC15190, ''3-D Reservoir and Stochastic Fracture Network Modeling for Enhanced Oil Recovery, Circle Ridge Phosphoria/Tensleep Reservoir, Wind River Reservation, Arapaho and Shoshone Tribes, Wyoming''. The goal of this project is to improve the recovery of oil from the Tensleep and Phosphoria Formations in Circle Ridge Oilfield, located on the Wind River Reservation in Wyoming, through an innovative integration of matrix characterization, structural reconstruction, and the characterization of the fracturing in the reservoir through the use of discrete fracture network models. Fields in which natural fractures dominate reservoir permeability, such as the Circle Ridge Field, often experience sub-optimal recovery when recovery processes are designed and implemented that do not take advantage of the fracture systems. For example, a conventional waterflood in a main structural block of the Field was implemented and later suspended due to unattractive results. It is estimated that somewhere less than 20% of the OOIP in the Circle Ridge Field have been recovered after more than 50 years' production. Marathon Oil Company identified the Circle Ridge Field as an attractive candidate for several advanced IOR processes that explicitly take advantage of the natural fracture system. These processes require knowledge of the distribution of matrix porosity, permeability and oil saturations; and understanding of where fracturing is likely to be well-developed or poorly developed; how the fracturing may compartmentalize the reservoir; and how smaller, relatively untested subthrust fault blocks may be connected to the main overthrust block. For this reason, the project focused on improving knowledge of the matrix properties, the fault block architecture and to develop a model that could be used to predict fracture intensity, orientation and fluid flow/connectivity properties. Knowledge

  14. Nonlinear Model Predictive Control for Oil Reservoirs Management

    DEFF Research Database (Denmark)

    Capolei, Andrea

    expensive gradient computation by using high-order ESDIRK (Explicit Singly Diagonally Implicit Runge-Kutta) temporal integration methods and continuous adjoints. The high order integration scheme allows larger time steps and therefore faster solution times. We compare gradient computation by the continuous...... gradient-based optimization and the required gradients are computed by the adjoint method. We propose the use of efficient high order implicit time integration methods for the solution of the forward and the adjoint equations of the dynamical model. The Ensemble Kalman filter is used for data assimilation...... equivalent strategy is not justified for the particular case studied in this paper. The third contribution of this thesis is a mean-variance method for risk mitigation in production optimization of oil reservoirs. We introduce a return-risk bicriterion objective function for the profit-risk tradeoff...

  15. Friction Theory Prediction of Crude Oil Viscosity at Reservoir Conditions Based on Dead Oil Properties

    DEFF Research Database (Denmark)

    Cisneros, Sergio; Zeberg-Mikkelsen, Claus Kjær; Stenby, Erling Halfdan

    2003-01-01

    The general one-parameter friction theory (f-theory) models have been further extended to the prediction of the viscosity of real "live" reservoir fluids based on viscosity measurements of the "dead" oil and the compositional information of the live fluid. This work representation of the viscosity...... of real fluids is obtained by a simple one-parameter tuning of a linear equation derived from a general one-parameter f-theory model. Further, this is achieved using simple cubic equations of state (EOS), such as the Peng-Robinson (PR) EOS or the Soave-Redlich-Kwong (SRK) EOS, which are commonly used...... within the oil industry. In sake of completeness, this work also presents a simple characterization procedure which is based on compositional information of an oil sample. This procedure provides a method for characterizing an oil into a number of compound groups along with the critical constants...

  16. Development of Permeable Reactive Barriers (PRB) Using Edible Oils

    Science.gov (United States)

    2008-06-01

    naturally occurring processes of advection and dispersion to bring the contaminants to the treatment barrier. A large scale approach would be to form a...process has been developed for distributing soybean oil as an oil-in-water emulsion consisting of small oil droplets dispersed in a continuous...Thiele Kaolin Company, Sandersville, Georgia) was added to certain materials to evaluate the effect of increasing clay content. Grain size

  17. Research of hard-to-recovery and unconventional oil-bearing formations according to the principle «in-situ reservoir fabric»

    OpenAIRE

    А. Д. Алексеев; В. В. Жуков; К. В. Стрижнев; С. А. Черевко

    2017-01-01

    Currently in Russia and the world due to the depletion of old highly productive deposits, the role of hard-to-recover and unconventional hydrocarbons is increasing. Thanks to scientific and technical progress, it became possible to involve in the development very low permeable reservoirs and even synthesize oil and gas in-situ. Today, wells serve not only for the production of hydrocarbons, but also are important elements of stimulation technology, through which the technogenic effect on the ...

  18. On the feasibility of inducing oil mobilization in existing reservoirs via wellbore harmonic fluid action

    KAUST Repository

    Jeong, Chanseok

    2011-03-01

    Although vibration-based mobilization of oil remaining in mature reservoirs is a promising low-cost method of enhanced oil recovery (EOR), research on its applicability at the reservoir scale is still at an early stage. In this paper, we use simplified models to study the potential for oil mobilization in homogeneous and fractured reservoirs, when harmonically oscillating fluids are injected/produced within a well. To this end, we investigate first whether waves, induced by fluid pressure oscillations at the well site, and propagating radially and away from the source in a homogeneous reservoir, could lead to oil droplet mobilization in the reservoir pore-space. We discuss both the fluid pore-pressure wave and the matrix elastic wave cases, as potential agents for increasing oil mobility. We then discuss the more realistic case of a fractured reservoir, where we study the fluid pore-pressure wave motion, while taking into account the leakage effect on the fracture wall. Numerical results show that, in homogeneous reservoirs, the rock-stress wave is a better energy-delivery agent than the fluid pore-pressure wave. However, neither the rock-stress wave nor the pore-pressure wave is likely to result in any significant residual oil mobilization at the reservoir scale. On the other hand, enhanced oil production from the fractured reservoir\\'s matrix zone, induced by cross-flow vibrations, appears to be feasible. In the fractured reservoir, the fluid pore-pressure wave is only weakly attenuated through the fractures, and thus could induce fluid exchange between the rock formation and the fracture space. The vibration-induced cross-flow is likely to improve the imbibition of water into the matrix zone and the expulsion of oil from it. © 2011 Elsevier B.V.

  19. Characterization of oil and gas reservoirs and recovery technology deployment on Texas State Lands

    Energy Technology Data Exchange (ETDEWEB)

    Tyler, R.; Major, R.P.; Holtz, M.H. [Univ. of Texas, Austin, TX (United States)] [and others

    1997-08-01

    Texas State Lands oil and gas resources are estimated at 1.6 BSTB of remaining mobile oil, 2.1 BSTB, or residual oil, and nearly 10 Tcf of remaining gas. An integrated, detailed geologic and engineering characterization of Texas State Lands has created quantitative descriptions of the oil and gas reservoirs, resulting in delineation of untapped, bypassed compartments and zones of remaining oil and gas. On Texas State Lands, the knowledge gained from such interpretative, quantitative reservoir descriptions has been the basis for designing optimized recovery strategies, including well deepening, recompletions, workovers, targeted infill drilling, injection profile modification, and waterflood optimization. The State of Texas Advanced Resource Recovery program is currently evaluating oil and gas fields along the Gulf Coast (South Copano Bay and Umbrella Point fields) and in the Permian Basin (Keystone East, Ozona, Geraldine Ford and Ford West fields). The program is grounded in advanced reservoir characterization techniques that define the residence of unrecovered oil and gas remaining in select State Land reservoirs. Integral to the program is collaboration with operators in order to deploy advanced reservoir exploitation and management plans. These plans are made on the basis of a thorough understanding of internal reservoir architecture and its controls on remaining oil and gas distribution. Continued accurate, detailed Texas State Lands reservoir description and characterization will ensure deployment of the most current and economically viable recovery technologies and strategies available.

  20. Visualized study of thermochemistry assisted steam flooding to improve oil recovery in heavy oil reservoir with glass micromodels

    NARCIS (Netherlands)

    Lyu, X.; Liu, Huiqing; Pang, Zhanxi; Sun, Zhixue

    2018-01-01

    Steam channeling, one serious problem in the process of steam flooding in heavy oil reservoir, decreases the sweep efficiency of steam to cause a lower oil recovery. Viscosity reducer and nitrogen foam, two effective methods to improve oil recovery with different mechanism, present a satisfactory

  1. Integrating Electrokinetic and Bioremediation Process for Treating Oil Contaminated Low Permeability Soil

    Directory of Open Access Journals (Sweden)

    Surya Ramadan Bimastyaji

    2018-01-01

    Full Text Available Traditional oil mining activities always ignores environmental regulation which may cause contamination in soil and environment. Crude oil contamination in low-permeability soil complicates recovery process because it requires substantial energy for excavating and crushing the soil. Electrokinetic technology can be used as an alternative technology to treat contaminated soil and improve bioremediation process (biostimulation through transfer of ions and nutrient that support microorganism growth. This study was conducted using a combination of electrokinetic and bioremediation processes. Result shows that the application of electrokinetic and bioremediation in low permeability soils can provide hydrocarbon removal efficiency up to 46,3% in 7 days operation. The highest amount of microorganism can be found in 3-days operation, which is 2x108 CFU/ml using surfactant as flushing fluid for solubilizing hydrocarbon molecules. Enhancing bioremediation using electrokinetic process is very potential to recover oil contaminated low permeability soil in the future.

  2. Integrating Electrokinetic and Bioremediation Process for Treating Oil Contaminated Low Permeability Soil

    Science.gov (United States)

    Ramadan, Bimastyaji Surya; Effendi, Agus Jatnika; Helmy, Qomarudin

    2018-02-01

    Traditional oil mining activities always ignores environmental regulation which may cause contamination in soil and environment. Crude oil contamination in low-permeability soil complicates recovery process because it requires substantial energy for excavating and crushing the soil. Electrokinetic technology can be used as an alternative technology to treat contaminated soil and improve bioremediation process (biostimulation) through transfer of ions and nutrient that support microorganism growth. This study was conducted using a combination of electrokinetic and bioremediation processes. Result shows that the application of electrokinetic and bioremediation in low permeability soils can provide hydrocarbon removal efficiency up to 46,3% in 7 days operation. The highest amount of microorganism can be found in 3-days operation, which is 2x108 CFU/ml using surfactant as flushing fluid for solubilizing hydrocarbon molecules. Enhancing bioremediation using electrokinetic process is very potential to recover oil contaminated low permeability soil in the future.

  3. Environmental Drivers of Differences in Microbial Community Structure in Crude Oil Reservoirs across a Methanogenic Gradient

    OpenAIRE

    Shelton, Jenna L.; Akob, Denise M.; McIntosh, Jennifer C.; Fierer, Noah; Spear, John R.; Warwick, Peter D.; McCray, John E.

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, a...

  4. Optimisation of production from an oil-reservoir using augmented Lagrangian methods

    Energy Technology Data Exchange (ETDEWEB)

    Doublet, Daniel Christopher

    2007-07-01

    This work studies the use of augmented Lagrangian methods for water flooding production optimisation from an oil reservoir. Commonly, water flooding is used as a means to enhance oil recovery, and due to heterogeneous rock properties, water will flow with different velocities throughout the reservoir. Due to this, water breakthrough can occur when great regions of the reservoir are still unflooded so that much of the oil may become 'trapped' in the reservoir. To avoid or reduce this problem, one can control the production so that the oil recovery rate is maximised, or alternatively the net present value (NPV) of the reservoir is maximised. We have considered water flooding, using smart wells. Smart wells with down-hole valves gives us the possibility to control the injection/production at each of the valve openings along the well, so that it is possible to control the flowregime. One can control the injection/production at all valve openings, and the setting of the valves may be changed during the production period, which gives us a great deal of control over the production and we want to control the injection/ production so that the profit obtained from the reservoir is maximised. The problem is regarded as an optimal control problem, and it is formulated as an augmented Lagrangian saddle point problem. We develop a method for optimal control based on solving the Karush-Kuhn-Tucker conditions for the augmented Lagrangian functional, a method, which to my knowledge has not been presented in the literature before. The advantage of this method is that we do not need to solve the forward problem for each new estimate of the control variables, which reduces the computational effort compared to other methods that requires the solution of the forward problem every time we find a new estimate of the control variables, such as the adjoint method. We test this method on several examples, where it is compared to the adjoint method. Our numerical experiments show

  5. An Experimental Study of Surfactant Alternating CO2 Injection for Enhanced Oil Recovery of Carbonated Reservoir

    Directory of Open Access Journals (Sweden)

    Asghar Gandomkar

    2016-10-01

    Full Text Available Core flooding experiments were conducted with the objective of evaluating near miscible surfactant alternating CO2 injection and the effect of surfactant concentrations on gas-oil and water displacements in porous media. The core samples were provided from a low permeability mixed wet oil reservoir at 156 °F and 1900 psia. In addition, very few studies of surfactant adsorption on carbonate minerals have been conducted. Hence, the surfactant adsorption on carbonate rock was determined by core flooding and crushed tests. It was found that for the crushed rock, the required equilibrium time is approximately five hours, while it is more than four days for the flow-through tests. Hysteresis effects demonstrated that the irreducible water saturations were 5 to 10% higher than the initial connate water saturation after drainage cycles during 5000 ppm surfactant solution. Furthermore, near-miscible surfactant alternating CO2 injection process led to a 4-17% increase in the recovery factor in comparison to water alternating gas process.

  6. CHARACTERIZATION OF IN-SITU STRESS AND PERMEABILITY IN FRACTURED RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Daniel R. Burns; M. Nafi Toksoz

    2002-12-31

    We have extended a three-dimensional finite difference elastic wave propagation model previously developed at the Massachusetts Institute of Technology (MIT) Earth Resources Laboratory (ERL) for modeling and analyzing the effect of fractures on seismic waves. The code has been translated into C language and parallelized [using message passing interface (MPI)] to allow for larger models to be run on Linux PC computer clusters. We have also obtained another 3-D code from Lawrence Berkeley Laboratory, which we will use for verification of our ERL code results and also to run discrete fracture models. Testing of both codes is underway. We are working on a new finite difference model of borehole wave propagation for stressed formations. This code includes coordinate stretching to provide stable, variable grid sizes that will allow us to model the thin fluid annulus layers in borehole problems, especially for acoustic logging while drilling (LWD) applications. We are also extending our analysis routines for the inversion of flexural wave dispersion measurements for in situ stress estimates. Initial results on synthetic and limited field data are promising for a method to invert cross dipole data for the rotation angle and stress state simultaneously. A meeting is being scheduled between MIT and Shell Oil Company scientists to look at data from a fractured carbonate reservoir that may be made available to the project. The Focus/Disco seismic processing system from Paradigm Geophysical has been installed at ERL for field data analysis and as a platform for new analysis modules. We have begun to evaluate the flow properties of discrete fracture distributions through a simple 2D numerical model. Initial results illustrate how fluid flow pathways are very sensitive to variations in the geometry and apertures of fracture network.

  7. Integrating Electrokinetic and Bioremediation Process for Treating Oil Contaminated Low Permeability Soil

    OpenAIRE

    Surya Ramadan Bimastyaji; Jatnika Effendi Agus; Helmy Qomarudin

    2018-01-01

    Traditional oil mining activities always ignores environmental regulation which may cause contamination in soil and environment. Crude oil contamination in low-permeability soil complicates recovery process because it requires substantial energy for excavating and crushing the soil. Electrokinetic technology can be used as an alternative technology to treat contaminated soil and improve bioremediation process (biostimulation) through transfer of ions and nutrient that support microorganism gr...

  8. Architecture and reservoir quality of low-permeable Eocene lacustrine turbidite sandstone from the Dongying Depression, East China

    Science.gov (United States)

    Munawar, Muhammad Jawad; Lin, Chengyan; Chunmei, Dong; Zhang, Xianguo; Zhao, Haiyan; Xiao, Shuming; Azeem, Tahir; Zahid, Muhammad Aleem; Ma, Cunfei

    2018-05-01

    The architecture and quality of lacustrine turbidites that act as petroleum reservoirs are less well documented. Reservoir architecture and multiscale heterogeneity in turbidites represent serious challenges to production performance. Additionally, establishing a hierarchy profile to delineate heterogeneity is a challenging task in lacustrine turbidite deposits. Here, we report on the turbidites in the middle third member of the Eocene Shahejie Formation (Es3), which was deposited during extensive Middle to Late Eocene rifting in the Dongying Depression. Seismic records, wireline log responses, and core observations were integrated to describe the reservoir heterogeneity by delineating the architectural elements, sequence stratigraphic framework and lithofacies assemblage. A petrographic approach was adopted to constrain microscopic heterogeneity using an optical microscope, routine core analyses and X-ray diffraction (XRD) analyses. The Es3m member is interpreted as a sequence set composed of four composite sequences: CS1, CS2, CS3 and CS4. A total of forty-five sequences were identified within these four composite sequences. Sand bodies were mainly deposited as channels, levees, overbank splays, lobes and lobe fringes. The combination of fining-upward and coarsening-upward lithofacies patterns in the architectural elements produces highly complex composite flow units. Microscopic heterogeneity is produced by diagenetic alteration processes (i.e., feldspar dissolution, authigenic clay formation and quartz cementation). The widespread kaolinization of feldspar and mobilization of materials enhanced the quality of the reservoir by producing secondary enlarged pores. In contrast, the formation of pore-filling authigenic illite and illite/smectite clays reduced its permeability. Recovery rates are higher in the axial areas and smaller in the marginal areas of architectural elements. This study represents a significant insight into the reservoir architecture and

  9. Research and application of multi-hydrogen acidizing technology of low-permeability reservoirs for increasing water injection

    Science.gov (United States)

    Ning, Mengmeng; Che, Hang; Kong, Weizhong; Wang, Peng; Liu, Bingxiao; Xu, Zhengdong; Wang, Xiaochao; Long, Changjun; Zhang, Bin; Wu, Youmei

    2017-12-01

    The physical characteristics of Xiliu 10 Block reservoir is poor, it has strong reservoir inhomogeneity between layers and high kaolinite content of the reservoir, the scaling trend of fluid is serious, causing high block injection well pressure and difficulty in achieving injection requirements. In the past acidizing process, the reaction speed with mineral is fast, the effective distance is shorter and It is also easier to lead to secondary sedimentation in conventional mud acid system. On this point, we raised multi-hydrogen acid technology, multi-hydrogen acid release hydrogen ions by multistage ionization which could react with pore blockage, fillings and skeletal effects with less secondary pollution. Multi-hydrogen acid system has advantages as moderate speed, deep penetration, clay low corrosion rate, wet water and restrains precipitation, etc. It can reach the goal of plug removal in deep stratum. The field application result shows that multi-hydrogen acid plug removal method has good effects on application in low permeability reservoir in Block Xiliu 10.

  10. Multigrid Methods for Fully Implicit Oil Reservoir Simulation

    Science.gov (United States)

    Molenaar, J.

    1996-01-01

    In this paper we consider the simultaneous flow of oil and water in reservoir rock. This displacement process is modeled by two basic equations: the material balance or continuity equations and the equation of motion (Darcy's law). For the numerical solution of this system of nonlinear partial differential equations there are two approaches: the fully implicit or simultaneous solution method and the sequential solution method. In the sequential solution method the system of partial differential equations is manipulated to give an elliptic pressure equation and a hyperbolic (or parabolic) saturation equation. In the IMPES approach the pressure equation is first solved, using values for the saturation from the previous time level. Next the saturations are updated by some explicit time stepping method; this implies that the method is only conditionally stable. For the numerical solution of the linear, elliptic pressure equation multigrid methods have become an accepted technique. On the other hand, the fully implicit method is unconditionally stable, but it has the disadvantage that in every time step a large system of nonlinear algebraic equations has to be solved. The most time-consuming part of any fully implicit reservoir simulator is the solution of this large system of equations. Usually this is done by Newton's method. The resulting systems of linear equations are then either solved by a direct method or by some conjugate gradient type method. In this paper we consider the possibility of applying multigrid methods for the iterative solution of the systems of nonlinear equations. There are two ways of using multigrid for this job: either we use a nonlinear multigrid method or we use a linear multigrid method to deal with the linear systems that arise in Newton's method. So far only a few authors have reported on the use of multigrid methods for fully implicit simulations. Two-level FAS algorithm is presented for the black-oil equations, and linear multigrid for

  11. Well pattern optimization in a low permeability sandstone reservoir: a case study from Erlian Basin in China

    Science.gov (United States)

    Wang, Xia; Fu, Lixia; Yan, Aihua; Guo, Fajun; Wu, Cong; Chen, Hong; Wang, Xinying; Lu, Ming

    2018-02-01

    Study on optimization of development well patterns is the core content of oilfield development and is a prerequisite for rational and effective development of oilfield. The study on well pattern optimization mainly includes types of well patterns and density of well patterns. This paper takes the Aer-3 fault block as an example. Firstly, models were built for diamond-shaped inverted 9-spot patterns, rectangular 5-spot patterns, square inverted 9-spot patterns and inverted 7-spot patterns under the same well pattern density to correlate the effect of different well patterns on development; secondly, comprehensive analysis was conducted to well pattern density in terms of economy and technology using such methods as oil reservoir engineering, numerical simulation, economic limits and economic rationality. Finally, the development mode of vertical well + horizontal well was presented according to the characteristics of oil reservoirs in some well blocks, which has realized efficient development of this fault block.

  12. Application of Integrated Reservoir Management and Reservoir Characterization to Optimize Infill Drilling

    Energy Technology Data Exchange (ETDEWEB)

    P. K. Pande

    1998-10-29

    Initial drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, must become a process of the past. Such efforts do not optimize reservoir development as they fail to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, and carbonate reservoirs in particular. These reservoirs are typically characterized by: o Large, discontinuous pay intervals o Vertical and lateral changes in reservoir properties o Low reservoir energy o High residual oil saturation o Low recovery efficiency

  13. Sulfate-Reducing Prokaryotes from North Sea Oil reservoirs; organisms, distribution and origin

    Energy Technology Data Exchange (ETDEWEB)

    Beeder, Janiche

    1996-12-31

    During oil production in the North Sea, anaerobic seawater is pumped in which stimulates the growth of sulphate-reducing prokaryotes that produce hydrogen sulphide. This sulphide causes major health hazards, economical and operational problems. As told in this thesis, several strains of sulphate reducers have been isolated from North Sea oil field waters. Antibodies have been produced against these strains and used to investigate the distribution of sulphate reducers in a North Sea oil reservoir. The result showed a high diversity among sulphate reducers, with different strains belonging to different parts of the reservoir. Some of these strains have been further characterized. The physiological and phylogenetic characterization showed that strain 7324 was an archaean. Strain A8444 was a bacterium, representing a new species of a new genus. A benzoate degrading sulphate reducing bacterium was isolated from injection water, and later the same strain was detected in produced water. This is the first field observations indicating that sulphate reducers are able to penetrate an oil reservoir. It was found that the oil reservoir contains a diverse population of thermophilic sulphate reducers able to grow on carbon sources in the oil reservoir, and to live and grow in this extreme environment of high temperature and pressure. The mesophilic sulphate reducers are established in the injection water system and in the reservoir near the injection well during oil production. The thermophilic sulphate reducers are able to grow in the reservoir prior to, as well as during production. It appears that the oil reservoir is a natural habitat for thermophilic sulphate reducers and that they have been present in the reservoir long before production started. 322 refs., 9 figs., 11 tabs.

  14. Sulfate-Reducing Prokaryotes from North Sea Oil reservoirs; organisms, distribution and origin

    Energy Technology Data Exchange (ETDEWEB)

    Beeder, Janiche

    1997-12-31

    During oil production in the North Sea, anaerobic seawater is pumped in which stimulates the growth of sulphate-reducing prokaryotes that produce hydrogen sulphide. This sulphide causes major health hazards, economical and operational problems. As told in this thesis, several strains of sulphate reducers have been isolated from North Sea oil field waters. Antibodies have been produced against these strains and used to investigate the distribution of sulphate reducers in a North Sea oil reservoir. The result showed a high diversity among sulphate reducers, with different strains belonging to different parts of the reservoir. Some of these strains have been further characterized. The physiological and phylogenetic characterization showed that strain 7324 was an archaean. Strain A8444 was a bacterium, representing a new species of a new genus. A benzoate degrading sulphate reducing bacterium was isolated from injection water, and later the same strain was detected in produced water. This is the first field observations indicating that sulphate reducers are able to penetrate an oil reservoir. It was found that the oil reservoir contains a diverse population of thermophilic sulphate reducers able to grow on carbon sources in the oil reservoir, and to live and grow in this extreme environment of high temperature and pressure. The mesophilic sulphate reducers are established in the injection water system and in the reservoir near the injection well during oil production. The thermophilic sulphate reducers are able to grow in the reservoir prior to, as well as during production. It appears that the oil reservoir is a natural habitat for thermophilic sulphate reducers and that they have been present in the reservoir long before production started. 322 refs., 9 figs., 11 tabs.

  15. Combustion for Enhanced Recovery of Light Oil at Medium Pressures

    NARCIS (Netherlands)

    Khoshnevis Gargar, N.

    2014-01-01

    Using conventional production methods, recovery percentages from oil reservoirs range from 5% for difficult oil to 50% for light oil in highly permeable homogeneous reservoirs. To increase the oil recovery factor, enhanced oil recovery (EOR) methods are used. We distinguish EOR that uses chemical

  16. Gradient-based methods for production optimization of oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Suwartadi, Eka

    2012-07-01

    Production optimization for water flooding in the secondary phase of oil recovery is the main topic in this thesis. The emphasis has been on numerical optimization algorithms, tested on case examples using simple hypothetical oil reservoirs. Gradientbased optimization, which utilizes adjoint-based gradient computation, is used to solve the optimization problems. The first contribution of this thesis is to address output constraint problems. These kinds of constraints are natural in production optimization. Limiting total water production and water cut at producer wells are examples of such constraints. To maintain the feasibility of an optimization solution, a Lagrangian barrier method is proposed to handle the output constraints. This method incorporates the output constraints into the objective function, thus avoiding additional computations for the constraints gradient (Jacobian) which may be detrimental to the efficiency of the adjoint method. The second contribution is the study of the use of second-order adjoint-gradient information for production optimization. In order to speedup convergence rate in the optimization, one usually uses quasi-Newton approaches such as BFGS and SR1 methods. These methods compute an approximation of the inverse of the Hessian matrix given the first-order gradient from the adjoint method. The methods may not give significant speedup if the Hessian is ill-conditioned. We have developed and implemented the Hessian matrix computation using the adjoint method. Due to high computational cost of the Newton method itself, we instead compute the Hessian-timesvector product which is used in a conjugate gradient algorithm. Finally, the last contribution of this thesis is on surrogate optimization for water flooding in the presence of the output constraints. Two kinds of model order reduction techniques are applied to build surrogate models. These are proper orthogonal decomposition (POD) and the discrete empirical interpolation method (DEIM

  17. Heavy oil reservoir evaluation : performing an injection test using DST tools in the marine region of Mexico

    Energy Technology Data Exchange (ETDEWEB)

    Loaiza, J.; Ruiz, P. [Halliburton, Mexico City (Mexico); Barrera, D.; Gutierrez, F. [Pemex, Mexico City (Mexico)

    2010-07-01

    This paper described an injection test conducted to evaluate heavy oil reserves in an offshore area of Mexico. The drill-stem testing (DST) evaluation used a fluid injection technique in order to eliminate the need for artificial lift and coiled tubing. A pressure transient analysis method was used to determine the static pressure of the reservoir, effective hydrocarbon permeability, and formation damage. Boundary effects were also characterized. The total volume of the fluid injection was determined by analyzing various reservoir parameters. The timing of the shut-in procedure was determined by characterizing rock characteristics and fluids within the reservoir. The mobility and diffusivity relationships between the zones with the injection fluids and reservoir fluids were used to defined sweep fluids. A productivity analysis was used to predict various production scenarios. DST tools were then used to conduct a pressure-production assessment. Case histories were used to demonstrate the method. The studies showed that the method provides a cost-effective means of providing high quality data for productivity analyses. 4 refs., 2 tabs., 15 figs.

  18. Solubility and Permeability Studies of Aceclofenac in Different Oils

    African Journals Online (AJOL)

    assess the in vivo bioavailability of the drug [1]. Forty percent of ... administration with hepatic first-pass metabolism. [11]. Due its ... suitable oils that would improve solubility and in .... Baboota S, Faisal MS, Ali J, Ahuja A. Effect of poloxamer.

  19. CO{sub 2} Huff-n-Puff process in a light oil shallow shelf carbonate reservoir. 1994 Annual report

    Energy Technology Data Exchange (ETDEWEB)

    Wehner, S.C.

    1995-05-01

    It is anticipated that this project will show that the application of the CO{sub 2} Huff-n-Puff process in shallow shelf carbonates can be economically implemented to recover appreciable volumes of light oil. The goals of the project are the development of guidelines for cost-effective selection of candidate reservoirs and wells, along with estimating recovery potential. The selected site for the demonstration project is the Central Vacuum Unit waterflood in Lea County, New Mexico. Work is nearing completion on the reservoir characterization components of the project. The near-term emphasis is to, (1) provide an accurate distribution of original oil-in-place on a waterflood pattern entity level, (2) evaluate past recovery efficiencies, (3) perform parametric simulations, and (4) forecast performance for a site specific field demonstration of the proposed technology. Macro zonation now exists throughout the study area and cross-sections are available. The Oil-Water Contact has been defined. Laboratory capillary pressure data was used to define the initial water saturations within the pay horizon. The reservoir`s porosity distribution has been enhanced with the assistance of geostatistical software. Three-Dimensional kriging created the spatial distributions of porosity at interwell locations. Artificial intelligence software was utilized to relate core permeability to core porosity, which in turn was applied to the 3-D geostatistical porosity gridding. An Equation-of-State has been developed and refined for upcoming compositional simulation exercises. Options for local grid-refinement in the model are under consideration. These tasks will be completed by mid-1995, prior to initiating the field demonstrations in the second budget period.

  20. Effect of retrograde gas condensate in low permeability natural gas reservoir; Efeito da condensacao retrograda em reservatorios de gas natural com baixa permeabilidade

    Energy Technology Data Exchange (ETDEWEB)

    Chang, Paulo Lee K.C. [Universidade Estadual de Campinas (UNICAMP), SP (Brazil). Faculdade de Engenharia Mecanica; Ligero, Eliana L.; Schiozer, Denis J. [Universidade Estadual de Campinas (UNICAMP), SP (Brazil). Faculdade de Engenharia Mecanica. Dept. de Engenharia de Petroleo

    2008-07-01

    Most of Brazilian gas fields are low-permeability or tight sandstone reservoirs and some of them should be gas condensate reservoir. In this type of natural gas reservoir, part of the gaseous hydrocarbon mixture is condensate and the liquid hydrocarbon accumulates near the well bore that causes the loss of productivity. The liquid hydrocarbon formation inside the reservoir should be well understood such as the knowledge of the variables that causes the condensate formation and its importance in the natural gas production. This work had as goal to better understanding the effect of condensate accumulation near a producer well. The influence of the porosity and the absolute permeability in the gas production was studied in three distinct gas reservoirs: a dry gas reservoir and two gas condensate reservoirs. The refinement of the simulation grid near the producer well was also investigated. The choice of simulation model was shown to be very important in the simulation of gas condensate reservoirs. The porosity was the little relevance in the gas production and in the liquid hydrocarbon formation; otherwise the permeability was very relevant. (author)

  1. Using Biosurfactants Produced from Agriculture Process Waste Streams to Improve Oil Recovery in Fractured Carbonate Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Stephen Johnson; Mehdi Salehi; Karl Eisert; Sandra Fox

    2009-01-07

    This report describes the progress of our research during the first 30 months (10/01/2004 to 03/31/2007) of the original three-year project cycle. The project was terminated early due to DOE budget cuts. This was a joint project between the Tertiary Oil Recovery Project (TORP) at the University of Kansas and the Idaho National Laboratory (INL). The objective was to evaluate the use of low-cost biosurfactants produced from agriculture process waste streams to improve oil recovery in fractured carbonate reservoirs through wettability mediation. Biosurfactant for this project was produced using Bacillus subtilis 21332 and purified potato starch as the growth medium. The INL team produced the biosurfactant and characterized it as surfactin. INL supplied surfactin as required for the tests at KU as well as providing other microbiological services. Interfacial tension (IFT) between Soltrol 130 and both potential benchmark chemical surfactants and crude surfactin was measured over a range of concentrations. The performance of the crude surfactin preparation in reducing IFT was greater than any of the synthetic compounds throughout the concentration range studied but at low concentrations, sodium laureth sulfate (SLS) was closest to the surfactin, and was used as the benchmark in subsequent studies. Core characterization was carried out using both traditional flooding techniques to find porosity and permeability; and NMR/MRI to image cores and identify pore architecture and degree of heterogeneity. A cleaning regime was identified and developed to remove organic materials from cores and crushed carbonate rock. This allowed cores to be fully characterized and returned to a reproducible wettability state when coupled with a crude-oil aging regime. Rapid wettability assessments for crushed matrix material were developed, and used to inform slower Amott wettability tests. Initial static absorption experiments exposed limitations in the use of HPLC and TOC to determine

  2. Effect of injection water quality on permeability of productive sands in Shaimsk group of oil fields

    Energy Technology Data Exchange (ETDEWEB)

    Andreeva, N I; Ivanov, V N; Lazarev, V N; Maksimov, V P

    1966-01-01

    Water from the Kond River is used to flood Shaimsk oil fields. Effect of raw and filtered waters on permeability of Shaimsk cores was experimentally determined. The raw river water contained 26 mg/liter of suspended solids, 10.7 mg/liter of total iron, 4.3 mg/liter of suspended iron oxide, and a pH of 6.4. The filtered river water was free of suspended solids and had a pH of 6.2. It was found that both raw and filtered water decreased core permeability. The unfiltered water decreased permeability 2 to 7 times more than the filtered water. Also, the decrease in permeability occurs much more slowly with the filtered than the unfiltered water. The effect of water on core permeability is essentially irreversible. Efforts to restore core permeability by reversing flow direction were not successful. Among the reasons for the permeability decrease were hydration and swelling of clays and evolution of gases from water in the cores. (10 refs.)

  3. Improving Oil Recovery (IOR) with Polymer Flooding in a Heavy-Oil River-Channel Sandstone Reservoir

    OpenAIRE

    Lu, Hongjiang

    2009-01-01

    Most of the old oil fields in China have reached high water cut stage, in order to meet the booming energy demanding, oil production rate must be kept in the near future with corresponding IOR (Improving Oil Recovery) methods. Z106 oilfield lies in Shengli Oilfields Area at the Yellow River delta. It was put into development in 1988. Since the oil belongs to heavy oil, the oil-water mobility ratio is so unfavourable that water cut increases very quickly. Especially for reservoir Ng21, the san...

  4. Preconditioning methods to improve SAGD performance in heavy oil and bitumen reservoirs with variable oil phase viscosity

    Energy Technology Data Exchange (ETDEWEB)

    Gates, I.D. [Gushor Inc., Calgary, AB (Canada)]|[Calgary Univ., AB (Canada). Dept. of Chemical and Petroleum Engineering; Larter, S.R.; Adams, J.J.; Snowdon, L.; Jiang, C. [Gushor Inc., Calgary, AB (Canada)]|[Calgary Univ., Calgary, AB (Canada). Dept. of Geoscience

    2008-10-15

    This study investigated preconditioning techniques for altering reservoir fluid properties prior to steam assisted gravity drainage (SAGD) recovery processes. Viscosity-reducing agents were distributed in mobile reservoir water. Simulations were conducted to demonstrate the method's ability to modify oil viscosity prior to steam injection. The study simulated the action of water soluble organic solvents that preferentially partitioned in the oil phase. The solvent was injected with water into the reservoir in a slow waterflood that did not displace oil from the near wellbore region. A reservoir simulation model was used to investigate the technique. Shu's correlation was used to establish a viscosity correlation for the bitumen and solvent mixtures. Solvent injection was modelled by converting the oil phase viscosity through time. Over the first 2 years, oil rates of the preconditioned case were double that of the non-preconditioned case study. However, after 11 years, the preconditioned case's rates declined below rates observed in the non-preconditioned case. The model demonstrated that oil viscosity distributions were significantly altered using the preconditioners. The majority of the most viscous oil surrounding the production well was significantly reduced. It was concluded that accelerated steam chamber growth provided faster access to lower viscosity materials at the top of the reservoir. 12 refs., 9 figs.

  5. Quantification of oil recovery efficiency, CO 2 storage potential, and fluid-rock interactions by CWI in heterogeneous sandstone oil reservoirs

    DEFF Research Database (Denmark)

    Seyyedi, Mojtaba; Sohrabi, Mehran; Sisson, Adam

    2017-01-01

    Significant interest exists in improving recovery from oil reservoirs while addressing concerns about increasing CO2 concentrations in the atmosphere. The combination of Enhanced Oil Recovery (EOR) and safe geologic storage of CO2 in oil reservoirs is appealing and can be achieved by carbonated (CO...... for oil recovery and CO2 storage potential on heterogeneous cores. Since not all the oil reservoirs are homogenous, understanding the potential of CWI as an integrated EOR and CO2 storage scenario in heterogeneous oil reservoirs is essential....

  6. Microbial conversion of higher hydrocarbons to methane in oil and coal reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Kruger, Martin; Beckmaann, Sabrina; Siegert, Michael; Grundger, Friederike; Richnow, Hans [Geomicrobiology Group, Federal Institute for Geosciences and Natural Resources (Germany)

    2011-07-01

    In recent years, oil production has increased enormously but almost half of the oil now remaining is heavy/biodegraded and cannot be put into production. There is therefore a need for new technology and for diversification of energy sources. This paper discusses the microbial conversion of higher hydrocarbons to methane in oil and coal reservoirs. The objective of the study is to identify microbial and geochemical controls on methanogenesis in reservoirs. A graph shows the utilization of methane for various purposes in Germany from 1998 to 2007. A degradation process to convert coal to methane is shown using a flow chart. The process for converting oil to methane is also given. Controlling factors include elements such as Fe, nitrogen and sulfur. Atmospheric temperature and reservoir pressure and temperature also play an important role. From the study it can be concluded that isotopes of methane provide exploration tools for reservoir selection and alkanes and aromatic compounds provide enrichment cultures.

  7. Numerical Modeling of Permeability Enhancement by Hydroshearing: the Case of Phase I Reservoir Creation at Fenton Hill

    Science.gov (United States)

    Rutqvist, J.; Rinaldi, A. P.

    2017-12-01

    The exploitation of a geothermal system is one of the most promising clean and almost inexhaustible forms of energy production. However, the exploitation of hot dry rock (HDR) reservoirs at depth requires circulation of a large amount of fluids. Indeed, the conceptual model of an Enhanced Geothermal System (EGS) requires that the circulation is enhanced by fluid injection. The pioneering experiments at Fenton Hill demonstrated the feasibility of EGS by producing the world's first HDR reservoirs. Such pioneering project demonstrated that the fluid circulation can be effectively enhanced by stimulating a preexisting fracture zone. The so-called "hydroshearing" involving shear activation of preexisting fractures is recognized as one of the main processes effectively enhancing permeability. The goal of this work is to quantify the effect of shear reactivation on permeability by proposing a model that accounts for fracture opening and shearing. We develop a case base on a pressure stimulation experiment at Fenton Hill, in which observation suggest that a fracture was jacked open by pressure increase. The proposed model can successfully reproduce such a behavior, and we compare the base case of pure elastic opening with the hydroshearing model to demonstrate that this latter could have occurred at the field, although no "felt" seismicity was observed. Then we investigate on the sensitivity of the proposed model by varying some of the critical parameters such as the maximum aperture, the dilation angle, as well as the fracture density.

  8. Investigation on behavior of bacteria in reservoir for microbial enhanced oil recovery; Biseibutsuho (MEOR) no tameno yusonai saikin katsudo ni kansuru chosa

    Energy Technology Data Exchange (ETDEWEB)

    Fujiwara, K.; Tanaka, S.; Otsuka, M.; Nakaya, K. [Kansai Research Institute, Kyoto (Japan). Lifescience Research Center; Maezumi, S.; Yazawa, N. [Japan National Oil Corp., Tokyo (Japan). Technology Research Center; Hong, C.; Chida, T.; Enomoto, H. [Tohoku University, Miyagi (Japan). Graduate School of Engineering

    2000-07-01

    Behavior of bacteria activated in reservoir though molasses-injection-tests, was investigated using the restriction fragment length polymorphism analysis with the polymerase chain reaction (PCR-RFLP) method, for elucidating potential bacteria to suppress in situ growth of microbes to be injected into the reservoir in the microbial enhanced oil recovery (MEOR) process. As a result, some bacteria belonging to Enterobacteriaceae species or their close relative species were grown predominantly in the reservoir, among bacteria inhibiting in the ground-water. The foregoing indicates that behavior of these bacteria in reservoir must be taken into consideration when giving a full account of behavior of microbes to be injected into the reservoir to put the MEOR process into operation. Potential proliferation using molasses to activate those bacteria was also estimated on the laboratory tests, to clarify the growth of microbes to be injected into the reservoir to operate the MEOR process. In consequence, it became clear that these bacteria have a potential growth exceeding 10{sup 8} CFU/ml, utilizing molasses. These facts indicated that microbes to be injected into the reservoir at the MEOR field tests are necessary to grow more excellently than bacteria inhabiting in the ground-water. In addition, as flow, the injection fluid is influenced by reservoir heterogeneity caused by injection of molasses, it was inferred that microbes to be injected into the reservoir at the MEOR field process are also necessary to grow more remarkably than bacteria inhabiting in the reservoir brine at high permeability zones and bacteria inhabiting in the reservoir rock. Furthermore, the results of the functional testing for MEOR conducted in the presence of bacteria activated through molasses-injection-tests indicated the importance of effective use of microbes to be injected, taking into account the characteristics of the reservoir and function for MEOR of those microbes. (author)

  9. Risk management in oil reservoir water-flooding under economic uncertainty

    NARCIS (Netherlands)

    Siraj, Muhammad; Van den Hof, Paul; Jansen, Jan Dirk

    2015-01-01

    Model-based economic optimization of the water-flooding process in oil reservoirs suffers from high levels of uncertainty. The achievable economic objective is highly uncertain due to the varying economic conditions and the limited knowledge of the reservoir model parameters. For improving

  10. Effect of Flow Direction on Relative Permeability Curves in Water/Gas Reservoir System: Implications in Geological CO2 Sequestration

    Directory of Open Access Journals (Sweden)

    Abdulrauf Rasheed Adebayo

    2017-01-01

    Full Text Available The effect of gravity on vertical flow and fluids saturation, especially when flow is against gravity, is not often a subject of interest to researchers. This is because of the notion that flow in subsurface formations is usually in horizontal direction and that vertical flow is impossible or marginal because of the impermeable shales or silts overlying them. The density difference between two fluids (usually oil and water flowing in the porous media is also normally negligible; hence gravity influence is neglected. Capillarity is also often avoided in relative permeability measurements in order to satisfy some flow equations. These notions have guided most laboratory core flooding experiments to be conducted in horizontal flow orientation, and the data obtained are as good as what the experiments tend to mimic. However, gravity effect plays a major role in gas liquid systems such as CO2 sequestration and some types of enhanced oil recovery techniques, particularly those involving gases, where large density difference exists between the fluid pair. In such cases, laboratory experiments conducted to derive relative permeability curves should take into consideration gravity effects and capillarity. Previous studies attribute directional dependence of relative permeability and residual saturations to rock anisotropy. It is shown in this study that rock permeability, residual saturation, and relative permeability depend on the interplay between gravity, capillarity, and viscous forces and also the direction of fluid flow even when the rock is isotropic. Rock samples representing different lithology and wide range of permeabilities were investigated through unsteady-state experiments covering drainage and imbibition in both vertical and horizontal flow directions. The experiments were performed at very low flow rates to capture capillarity. The results obtained showed that, for each homogeneous rock and for the same flow path along the core length

  11. Improvement of Carbon Dioxide Sweep Efficiency by Utilization of Microbial Permeability Profile Modification to Reduce the Amount of Oil Bypassed During Carbon Dioxide Flood

    Energy Technology Data Exchange (ETDEWEB)

    Schmitz, Darrel [Mississippi State Univ., Mississippi State, MS (United States); Brown, Lewis [Mississippi State Univ., Mississippi State, MS (United States); Lynch, F. Leo [Mississippi State Univ., Mississippi State, MS (United States); Kirkland, Brenda L. [Mississippi State Univ., Mississippi State, MS (United States); Collins, Krystal M. [Mississippi State Univ., Mississippi State, MS (United States); Funderburk, William K. [Mississippi State Univ., Mississippi State, MS (United States)

    2010-12-31

    The objective of this project was to couple microbial permeability profile modification (MPPM), with carbon dioxide flooding to improve oil recovery from the Upper Cretaceous Little Creek Oil Field situated in Lincoln and Pike counties, MS. This study determined that MPPM technology, which improves production by utilizing environmentally friendly nutrient solutions to simulate the growth of the indigenous microflora in the most permeable zones of the reservoir thus diverting production to less permeable, previously unswept zones, increased oil production without interfering with the carbon dioxide flooding operation. Laboratory tests determined that no microorganisms were produced in formation waters, but were present in cores. Perhaps the single most significant contribution of this study is the demonstration that microorganisms are active at a formation temperature of 115°C (239°F) by using a specially designed culturing device. Laboratory tests were employed to simulate the MPPM process by demonstrating that microorganisms could be activated with the resulting production of oil in coreflood tests performed in the presence of carbon dioxide at 66°C (the highest temperature that could be employed in the coreflood facility). Geological assessment determined significant heterogeneity in the Eutaw Formation, and documented relatively thin, variably-lithified, well-laminated sandstone interbedded with heavily-bioturbated, clay-rich sandstone and shale. Live core samples of the Upper Cretaceous Eutaw Formation from the Heidelberg Field, MS were quantitatively assessed using SEM, and showed that during MPPM permeability modification occurs ubiquitously within pore and throat spaces of 10-20 μm diameter. Testing of the MPPM procedure in the Little Creek Field showed a significant increase in production occurred in two of the five production test wells; furthermore, the decline curve in each of the production wells became noticeably less steep. This project greatly

  12. Thermochemical ablation therapy of VX2 tumor using a permeable oil-packed liquid alkali metal.

    Directory of Open Access Journals (Sweden)

    Ziyi Guo

    Full Text Available Alkali metal appears to be a promising tool in thermochemical ablation, but, it requires additional data on safety is required. The objective of this study was to explore the effectiveness of permeable oil-packed liquid alkali metal in the thermochemical ablation of tumors.Permeable oil-packed sodium-potassium (NaK was prepared using ultrasonic mixing of different ratios of metal to oil. The thermal effect of the mixture during ablation of muscle tissue ex vivo was evaluated using the Fluke Ti400 Thermal Imager. The thermochemical effect of the NaK-oil mixture on VX2 tumors was evaluated by performing perfusion CT scans both before and after treatment in 10 VX2 rabbit model tumors. VX2 tumors were harvested from two rabbits immediately after treatment to assess their viability using trypan blue and hematoxylin and eosin (H.E. staining.The injection of the NaK-oil mixture resulted in significantly higher heat in the ablation areas. The permeable oil controlled the rate of heat released during the NaK reaction with water in the living tissue. Perfusion computed tomography and its parameter map confirmed that the NaK-oil mixture had curative effects on VX2 tumors. Both trypan blue and H.E. staining showed partial necrosis of the VX2 tumors.The NaK-oil mixture may be used successfully to ablate tumor tissue in vivo. With reference to the controlled thermal and chemical lethal injury to tumors, using a liquid alkali in ablation is potentially an effective and safe method to treat malignant tumors.

  13. Porosity and permeability evolution of vesicular basalt reservoirs with increasing depth: constraints from the Big Island of Hawai'i

    Science.gov (United States)

    Millett, John; Haskins, Eric; Thomas, Donald; Jerram, Dougal; Planke, Sverre; Healy, Dave; Kück, Jochem; Rossetti, Lucas; Farrell, Natalie; Pierdominici, Simona

    2017-04-01

    Volcanic reservoirs are becoming increasingly important in the targeting of petroleum, geothermal and water resources globally. However, key areas of uncertainty in relation to volcanic reservoir properties during burial in different settings remain. In this contribution, we present results from borehole logging and sampling operations within two fully cored c. 1.5 km deep boreholes, PTA2 and KMA1, from the Humúula saddle region on the Big Island of Hawai'i. The boreholes were drilled as part of the Humu'ula Groundwater Research Project (HGRP) between 2013-2016 and provide unique insights into the evolution of pore structure with increasing burial in a basaltic dominated lava sequence. The boreholes encounter mixed sequences of 'a'ā, pāhoehoe and transitional lava flows along with subsidiary intrusions and sediments from the shield to post-shield phases of Mauna Kea. Borehole wireline data including sonic, spectral gamma and Televiewer imagery were collected along with density, porosity, permeability and ultrasonic velocity laboratory measurements from core samples. A range of intra-facies were sampled for analysis from various depths within the two boreholes. By comparison with core data, the potential for high resolution Televiewer imaging to reveal spectacular intra-facies features including individual vesicles, vesicle segregations, 'a'ā rubble zones, intrusive contacts, and intricate pāhoehoe lava flow lobe morphologies is demonstrated. High quality core data enables the calibration of Televiewer facies enabling improved interpretation of volcanic reservoir features in the more common exploration scenario where core is absent. Laboratory results record the ability of natural vesicular basalt samples to host very high porosity (>50%) and permeability (>10 darcies) within lava flow top facies which we demonstrate are associated with vesicle coalescence and not micro-fractures. These properties may be maintained to depths of c. 1.5 km in regions of limited

  14. A study of relations between physicochemical properties of crude oils and microbiological characteristics of reservoir microflora

    Science.gov (United States)

    Yashchenko, I. G.; Polishchuk, Yu. M.; Peremitina, T. O.

    2015-10-01

    The dependence of the population and activity of reservoir microflora upon the chemical composition and viscosity of crude oils has been investigated, since it allows the problem of improvement in the technologies and enhancement of oil recovery as applied to production of difficult types of oils with anomalous properties (viscous, heavy, waxy, high resin) to be solved. The effect of the chemical composition of the oil on the number, distribution, and activity of reservoir microflora has been studied using data on the microbiological properties of reservoir water of 16 different fields in oil and gas basins of Russia, Mongolia, China, and Vietnam. Information on the physicochemical properties of crude oils of these fields has been obtained from the database created at the Institute of Petroleum Chemistry, Siberian Branch on the physicochemical properties of oils throughout the world. It has been found that formation water in viscous oil reservoirs is char acterized by a large population of heterotrophic and sulfate reducing bacteria and the water of oil fields with a high paraffin content, by population of denitrifying bacteria.

  15. Oil recovery from naturally fractured reservoirs by steam injection methods. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Reis, J.C.; Miller, M.A.

    1995-05-01

    Oil recovery by steam injection is a proven, successful technology for nonfractured reservoirs, but has received only limited study for fractured reservoirs. Preliminary studies suggest recovery efficiencies in fractured reservoirs may be increased by as much as 50% with the application of steam relative to that of low temperature processes. The key mechanisms enhancing oil production at high temperature are the differential thermal expansion between oil and the pore volume, and the generation of gases within matrix blocks. Other mechanisms may also contribute to increased production. These mechanisms are relatively independent of oil gravity, making steam injection into naturally fractured reservoirs equally attractive to light and heavy oil deposits. The objectives of this research program are to quantify the amount of oil expelled by these recovery mechanisms and to develop a numerical model for predicting oil recovery in naturally fractured reservoirs during steam injection. The experimental study consists of constructing and operating several apparatuses to isolate each of these mechanisms. The first measures thermal expansion and capillary imbibition rates at relatively low temperature, but for various lithologies and matrix block shapes. The second apparatus measures the same parameters, but at high temperatures and for only one shape. A third experimental apparatus measures the maximum gas saturations that could build up within a matrix block. A fourth apparatus measures thermal conductivity and diffusivity of porous media. The numerical study consists of developing transfer functions for oil expulsion from matrix blocks to fractures at high temperatures and incorporating them, along with the energy equation, into a dual porosity thermal reservoir simulator. This simulator can be utilized to make predictions for steam injection processes in naturally-fractured reservoirs. Analytical models for capillary imbibition have also been developed.

  16. Analysis of stress sensitivity and its influence on oil productionfrom tight reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Lei, Qun; Xiong, Wei; Yuan, Cui; Wu, Yu-Shu

    2007-08-28

    This paper presents a study of the relationship betweenpermeability and effective stress in tight petroleum reservoirformations. Specifically, a quantitative method is developed to describethe correlation between permeability and effective stress, a method basedon the original in situ reservoir effective stress rather than ondecreased effective stress during development. The experimental resultsshow that the relationship between intrinsic permeability and effectivestress in reservoirs in general follows a quadratic polynomial functionalform, found to best capture how effective stress influences formationpermeability. In addition, this experimental study reveals that changesin formation permeability, caused by both elastic and plasticdeformation, are permanent and irreversible. Related pore-deformationtests using electronic microscope scanning and constant-rate mercuryinjection techniques show that while stress variation generally has smallimpact onrock porosity, the size and shape of pore throats have asignificant impact on permeability-stress sensitivity. Based on the testresults and theoretical analyses, we believe that there exists a cone ofpressure depression in the area near production within suchstress-sensitive tight reservoirs, leading to a low-permeability zone,and that well production will decrease under the influence of stresssensitivity.

  17. Wettability Alteration of Sandstone and Carbonate Rocks by Using ZnO Nanoparticles in Heavy Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Masoumeh Tajmiri

    2015-10-01

    Full Text Available Efforts to enhance oil recovery through wettability alteration by nanoparticles have been attracted in recent years. However, many basic questions have been ambiguous up until now. Nanoparticles penetrate into pore volume of porous media, stick on the core surface, and by creating homogeneous water-wet area, cause to alter wettability. This work introduces the new concept of adding ZnO nanoparticles by an experimental work on wettability alteration and oil recovery through spontaneous imbibition mechanism. Laboratory tests were conducted in two experimental steps on four cylindrical core samples (three sandstones and one carbonate taken from a real Iranian heavy oil reservoir in Amott cell. In the first step, the core samples were saturated by crude oil. Next, the core samples were flooded with nanoparticles and saturated by crude oil for about two weeks. Then, the core samples were immersed in distilled water and the amount of recovery was monitored during 30 days for both steps. The experimental results showed that oil recovery for three sandstone cores changed from 20.74, 4.3, and 3.5% of original oil in place (OOIP in the absence of nanoparticles to 36.2, 17.57, and 20.68% of OOIP when nanoparticles were added respectively. Moreover, for the carbonate core, the recovery changed from zero to 8.89% of OOIP by adding nanoparticles. By the investigation of relative permeability curves, it was found that by adding ZnO nanoparticles, the crossover-point of curves shifted to the right for both sandstone and carbonate cores, which meant wettability was altered to water- wet. This study, for the first time, illustrated the remarkable role of ZnO nanoparticles in wettability alteration toward more water-wet for both sandstone and carbonate cores and enhancing oil recovery.

  18. Cyclicity and reservoir properties of Lower-Middle Miocene sediments of South Kirinsk oil and gas field

    Science.gov (United States)

    Kurdina, Nadezhda

    2017-04-01

    Exploration and additional exploration of oil and gas fields, connected with lithological traps, include the spreading forecast of sedimentary bodies with reservoir and seal properties. Genetic identification and forecast of geological bodies are possible in case of large-scale studies, based on the study of cyclicity, structural and textural features of rocks, their composition, lithofacies and depositional environments. Porosity and permeability evaluation of different reservoir groups is also an important part. Such studies have been successfully completed for productive terrigenous Dagi sediments (Lower-Middle Miocene) of the north-eastern shelf of Sakhalin. In order to identify distribution of Dagi reservoirs with different properties in section, core material of the one well of South Kirinsk field has been studied (depth interval from 2902,4 to 2810,5 m). Productive Dagi deposits are represented by gray-colored sandstones with subordinate siltstones and claystones (total thickness 90,5 m). Analysis of cyclicity is based on the concepts of Vassoevich (1977), who considered cycles as geological body, which is the physical result of processes that took place during the sedimentation cycle. Well section was divided into I-X units with different composition and set of genetic features due to layered core description and elementary cyclites identification. According to description of thin sections and results of cylindrical samples porosity and permeability studies five groups of reservoirs were determined. There are coarse-grained and fine-coarse-grained sandstones, fine-grained sandstones, fine-grained silty sandstones, sandy siltstones and siltstones. It was found, in Dagi section there is interval of fine-coarse-grained and coarse-grained sandstones with high petrophysical properties: permeability 3000 mD, porosity more than 25%, but rocks with such properties spread locally and their total thickness is 6 meters only. This interval was described in the IV unit

  19. A simulation method for the rapid screening of potential depleted oil reservoirs for CO2 sequestration

    International Nuclear Information System (INIS)

    Bossie-Codreanu, D.; Le Gallo, Y.

    2004-01-01

    The reduction of greenhouse gases emission is a growing concern of many industries. The oil and gas industry has a long commercial practice of gas injection, enhanced oil recovery (EOR) and gas storage. Using a depleted oil or gas reservoir for CO 2 storage has several interesting advantages. The long-term risk analysis of the CO 2 behavior and its impact on the environment is a major concern. That is why the selection of an appropriate reservoir is crucial to the success of a sequestration operation. Our modeling study, based on a synthetic reservoir, quantifies uncertainties due to reservoir parameters in order to establish a set of guidelines to select the most appropriate depleted reservoirs. Several production and sequestration scenarios are investigated in order to quantify key parameter for CO 2 storage. The influence of parameters such as API gravity, heterogeneity (Dykstra-Parson coefficient), pressure support (water injection) and cap rock integrity are analyzed. Estimation of sequestration capacity is proposed through a sequestration factor (SF) estimated for different reservoir production drives. Multiple regression relationships were developed, allowing SF estimation. CO 2 sequestration optimization highlights the best clean oil recovery strategy (CO 2 injection and/or oil production)

  20. CHARACTERIZATION OF IN-SITU STRESS AND PERMEABILITY IN FRACTURED RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Daniel R. Burns; M. Nafi Toksoz

    2005-02-04

    Numerical modeling and field data tests are presented on the Transfer Function/Scattering Index Method for estimating fracture orientation and density in subsurface reservoirs from the ''coda'' or scattered energy in the seismic trace. Azimuthal stacks indicate that scattered energy is enhanced along the fracture strike direction. A transfer function method is used to more effectively indicate fracture orientation. The transfer function method, which involves a comparison of the seismic signature above and below a reservoir interval, effectively eliminates overburden effects and acquisition imprints in the analysis. The transfer function signature is simplified into a scattering index attribute value that gives fracture orientation and spatial variations of the fracture density within a field. The method is applied to two field data sets, a 3-D Ocean Bottom Cable (OBC) seismic data set from an offshore fractured carbonate reservoir in the Adriatic Sea and a 3-D seismic data set from an onshore fractured carbonate field in the Middle East. Scattering index values are computed in both fields at the reservoir level, and the results are compared to borehole breakout data and Formation MicroImager (FMI) logs in nearby wells. In both cases the scattering index results are in very good agreement with the well data. Field data tests and well validation will continue. In the area of technology transfer, we have made presentations of our results to industry groups at MIT technical review meetings, international technical conferences, industry workshops, and numerous exploration and production company visits.

  1. Characterization of fracture reservoirs using static and dynamic data: From sonic and 3D seismic to permeability distribution. Annual report, March 1, 1996--February 28, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Parra, J.O.; Collier, H.A.; Owen, T.E. [and others

    1997-06-01

    In low porosity, low permeability zones, natural fractures are the primary source of permeability which affect both production and injection of fluids. The open fractures do not contribute much to porosity, but they provide an increased drainage network to any porosity. They also may connect the borehole to remote zones of better reservoir characteristics. An important approach to characterizing the fracture orientation and fracture permeability of reservoir formations is one based on the effects of such conditions on the propagation of acoustic and seismic waves in the rock. The project is a study directed toward the evaluation of acoustic logging and 3D-seismic measurement techniques as well as fluid flow and transport methods for mapping permeability anisotropy and other petrophysical parameters for the understanding of the reservoir fracture systems and associated fluid dynamics. The principal application of these measurement techniques and methods is to identify and investigate the propagation characteristics of acoustic and seismic waves in the Twin Creek hydrocarbon reservoir owned by Union Pacific Resources (UPR) and to characterize the fracture permeability distribution using production data. This site is located in the overthrust area of Utah and Wyoming. UPR drilled six horizontal wells, and presently UPR has two rigs running with many established drill hole locations. In addition, there are numerous vertical wells that exist in the area as well as 3D seismic surveys. Each horizontal well contains full FMS logs and MWD logs, gamma logs, etc.

  2. Experimental research on microscopic displacement mechanism of CO2-water alternative flooding in low permeability reservoir

    Science.gov (United States)

    Han, Hongyan; Zhu, Weiyao; Long, Yunqian; Song, Hongqing; Huang, Kun

    2018-02-01

    This paper provides an experimental method to deal with the problems of low oil recovery ratio faced with water flooding utilizing the CO2/water alternate displacement technology. A series of CO2/water alternate flooding experiments were carried out under 60°C and 18.4MPa using high temperature / pressure microscopic visualization simulation system. Then, we used the image processing technique and software to analyze the proportion of remaining oil in the displacement process. The results show that CO2 can extract the lighter chemical components in the crude oil and make it easier to form miscible phase, which can reduce the viscosity and favorable mobility ratio of oil. What’s more, the displacement reduces the impact of gas channeling, which can achieve an enlarged sweeping efficiency to improve filtration ability. In addition, the CO2 dissolved in oil and water can greatly reduce the interfacial tension, which can increase the oil displacement efficiency in a large extent. Generally speaking, the recovery rate of residual oil in the micro - model can be elevated up to 15.89% ∼ 16.48% under formation condition by alternate displacement.

  3. Design and implementation of a caustic flooding EOR pilot at Court Bakken heavy oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Xie, J.; Chung, B.; Leung, L. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[Nexen Inc., Calgary, AB (Canada)

    2008-10-15

    Successful waterflooding has been ongoing since 1988 at the Court Bakken heavy oil field in west central Saskatchewan. There are currently 20 injectors and 28 active oil producers in the Court main unit which is owned by Nexen and Pengrowth. The Court pool has an estimated 103.8 mmbbl of original oil in place (OOIP), of which 24 per cent has been successfully recovered after 20 years of waterflooding. A high-level enhanced oil recovery (EOR) screening study was conducted to evaluate other EOR technologies for a heavy oil reservoir of this viscosity range (17 degrees API). Laboratory studies showed that caustic flooding may enhance oil recovery after waterflooding at the Court Bakken heavy oil pool. A single well test demonstrated that caustic injection effectively reduced residual oil saturation. A sector model reservoir simulation revealed that caustic flood could achieve 9 per cent incremental oil recovery in the pilot area. Following the promising laboratory results, a successful caustic flood pilot was implemented at Court heavy oil pool where the major challenges encountered were low reservoir pressure and water channeling. 6 refs., 2 tabs., 6 figs.

  4. Fracture density determination using a novel hybrid computational scheme: a case study on an Iranian Marun oil field reservoir

    International Nuclear Information System (INIS)

    Nouri-Taleghani, Morteza; Mahmoudifar, Mehrzad; Shokrollahi, Amin; Tatar, Afshin; Karimi-Khaledi, Mina

    2015-01-01

    Most oil production all over the world is from carbonated reservoirs. Carbonate reservoirs are abundant in the Middle East, the Gulf of Mexico and in other major petroleum fields that are regarded as the main oil producers. Due to the nature of such reservoirs that are associated with low matrix permeability, the fracture is the key parameter that governs the fluid flow in porous media and consequently oil production. Conventional methods to determine the fracture density include utilizing core data and the image log family, which are both time consuming and costly processes. In addition, the cores are limited to certain intervals and there is no image log for the well drilled before the introduction of this tool. These limitations motivate petroleum engineers to try to find appropriate alternatives. Recently, intelligent systems on the basis of machine learning have been applied to various branches of science and engineering. The objective of this study is to develop a mathematical model to predict the fracture density using full set log data as inputs based on a combination of three intelligent systems namely, the radial basis function neural network, the multilayer perceptron neural network and the least square supported vector machine. The developed committee machine intelligent system (CMIS) is the weighted average of the individual results of each expert. Proper corresponding weights are determined using a genetic algorithm (GA). The other important feature of the proposed model is its generalization capability. The ability of this model to predict data that have not been introduced during the training stage is very good. (paper)

  5. Microbial dynamics in petroleum oilfields and their relationship with physiological properties of petroleum oil reservoirs.

    Science.gov (United States)

    Varjani, Sunita J; Gnansounou, Edgard

    2017-12-01

    Petroleum is produced by thermal decay of buried organic material over millions of years. Petroleum oilfield ecosystems represent resource of reduced carbon which favours microbial growth. Therefore, it is obvious that many microorganisms have adapted to harsh environmental conditions of these ecosystems specifically temperature, oxygen availability and pressure. Knowledge of microorganisms present in ecosystems of petroleum oil reservoirs; their physiological and biological properties help in successful exploration of petroleum. Understanding microbiology of petroleum oilfield(s) can be used to enhance oil recovery, as microorganisms in oil reservoirs produce various metabolites viz. gases, acids, solvents, biopolymers and biosurfactants. The aim of this review is to discuss characteristics of petroleum oil reservoirs. This review also provides an updated literature on microbial ecology of these extreme ecosystems including microbial origin as well as various types of microorganisms such as methanogens; iron, nitrate and sulphate reducing bacteria, and fermentative microbes present in petroleum oilfield ecosystems. Copyright © 2017 Elsevier Ltd. All rights reserved.

  6. Conservation value and permeability of neotropical oil palm landscapes for orchid bees.

    Directory of Open Access Journals (Sweden)

    George Livingston

    Full Text Available The proliferation of oil palm plantations has led to dramatic changes in tropical landscapes across the globe. However, relatively little is known about the effects of oil palm expansion on biodiversity, especially in key ecosystem-service providing organisms like pollinators. Rapid land use change is exacerbated by limited knowledge of the mechanisms causing biodiversity decline in the tropics, particularly those involving landscape features. We examined these mechanisms by undertaking a survey of orchid bees, a well-known group of Neotropical pollinators, across forest and oil palm plantations in Costa Rica. We used chemical baits to survey the community in four regions: continuous forest sites, oil palm sites immediately adjacent to forest, oil palm sites 2 km from forest, and oil palm sites greater than 5 km from forest. We found that although orchid bees are present in all environments, orchid bee communities diverged across the gradient, and community richness, abundance, and similarity to forest declined as distance from forest increased. In addition, mean phylogenetic distance of the orchid bee community declined and was more clustered in oil palm. Community traits also differed with individuals in oil palm having shorter average tongue length and larger average geographic range size than those in the forest. Our results indicate two key features about Neotropical landscapes that contain oil palm: 1 oil palm is selectively permeable to orchid bees and 2 orchid bee communities in oil palm have distinct phylogenetic and trait structure compared to communities in forest. These results suggest that conservation and management efforts in oil palm-cultivating regions should focus on landscape features.

  7. Computer Modeling of the Displacement Behavior of Carbon Dioxide in Undersaturated Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Ju Binshan

    2015-11-01

    Full Text Available The injection of CO2 into oil reservoirs is performed not only to improve oil recovery but also to store CO2 captured from fuel combustion. The objective of this work is to develop a numerical simulator to predict quantitatively supercritical CO2 flooding behaviors for Enhanced Oil Recovery (EOR. A non-isothermal compositional flow mathematical model is developed. The phase transition diagram is designed according to the Minimum Miscibility Pressure (MMP and CO2 maximum solubility in oil phase. The convection and diffusion of CO2 mixtures in multiphase fluids in reservoirs, mass transfer between CO2 and crude and phase partitioning are considered. The governing equations are discretized by applying a fully implicit finite difference technique. Newton-Raphson iterative technique was used to solve the nonlinear equation systems and a simulator was developed. The performances of CO2 immiscible and miscible flooding in oil reservoirs are predicted by the new simulator. The distribution of pressure and temperature, phase saturations, mole fraction of each component in each phase, formation damage caused by asphaltene precipitation and the improved oil recovery are predicted by the simulator. Experimental data validate the developed simulator by comparison with simulation results. The applications of the simulator in prediction of CO2 flooding in oil reservoirs indicate that the simulator is robust for predicting CO2 flooding performance.

  8. Estimation of oil reservoir thermal properties through temperature log data using inversion method

    International Nuclear Information System (INIS)

    Cheng, Wen-Long; Nian, Yong-Le; Li, Tong-Tong; Wang, Chang-Long

    2013-01-01

    Oil reservoir thermal properties not only play an important role in steam injection well heat transfer, but also are the basic parameters for evaluating the oil saturation in reservoir. In this study, for estimating reservoir thermal properties, a novel heat and mass transfer model of steam injection well was established at first, this model made full analysis on the wellbore-reservoir heat and mass transfer as well as the wellbore-formation, and the simulated results by the model were quite consistent with the log data. Then this study presented an effective inversion method for estimating the reservoir thermal properties through temperature log data. This method is based on the heat transfer model in steam injection wells, and can be used to predict the thermal properties as a stochastic approximation method. The inversion method was applied to estimate the reservoir thermal properties of two steam injection wells, it was found that the relative error of thermal conductivity for the two wells were 2.9% and 6.5%, and the relative error of volumetric specific heat capacity were 6.7% and 7.0%,which demonstrated the feasibility of the proposed method for estimating the reservoir thermal properties. - Highlights: • An effective inversion method for predicting the oil reservoir thermal properties was presented. • A novel model for steam injection well made full study on the wellbore-reservoir heat and mass transfer. • The wellbore temperature field and steam parameters can be simulated by the model efficiently. • Both reservoirs and formation thermal properties could be estimated simultaneously by the proposed method. • The estimated steam temperature was quite consistent with the field data

  9. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    Energy Technology Data Exchange (ETDEWEB)

    Buckley, Jill S.

    2002-01-29

    The objectives of this five-year project were: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding.

  10. Spectral SP: A New Approach to Mapping Reservoir Flow and Permeability

    Energy Technology Data Exchange (ETDEWEB)

    Thomas, Donald M. [Univ. of Hawaii, Honolulu, HI (United States). Hawaii Inst. of Geophysics; Lienert, Barry R. [Univ. of Hawaii, Honolulu, HI (United States). Hawaii Inst. of Geophysics; Wallin, Erin L. [Univ. of Hawaii, Honolulu, HI (United States); Gasperikova, Erika [Lawrence Berkeley National Lab. (LBNL), Berkeley, CA (United States)

    2014-05-27

    Our objectives for the current project were to develop an innovative inversion and analysis procedure for magnetotelluric field data and time variable self-potentials that will enable us to map not only the subsurface resistivity structure of a geothermal prospect but to also delineate the permeability distribution within the field. Hence, the ultimate objective were to provide better targeting information for exploratory and development drilling of a geothermal prospect. Field data were collected and analyzed from the Kilauea Summit, Kilauea East Rift Zone, and the Humuula Saddle between Mauna Loa and Mauna Kea volcanoes. All of these areas were known or suspected to have geothermal activity of varying intensities. Our results provided evidence for significant long-term coordinated changes in spontaneous potential that could be associated with subsurface flows, significant interferences were encountered that arose from surface environmental changes (rainfall, temperature) that rendered it nearly impossible to unequivocally distinguish between deep fluid flow changes and environmental effects. Further, the analysis of the inferred spontaneous potential changes in the context of depth of the signals, and hence, permeability horizons, were unable to be completed in the time available.

  11. Multiphase flow modeling of a crude-oil spill site with a bimodal permeability distribution

    Science.gov (United States)

    Dillard, Leslie A.; Essaid, Hedeff I.; Herkelrath, William N.

    1997-01-01

    Fluid saturation, particle-size distribution, and porosity measurements were obtained from 269 core samples collected from six boreholes along a 90-m transect at a subregion of a crude-oil spill site, the north pool, near Bemidji, Minnesota. The oil saturation data, collected 11 years after the spill, showed an irregularly shaped oil body that appeared to be affected by sediment spatial variability. The particle-size distribution data were used to estimate the permeability (k) and retention curves for each sample. An additional 344 k estimates were obtained from samples previously collected at the north pool. The 613 k estimates were distributed bimodal lognormally with the two population distributions corresponding to the two predominant lithologies: a coarse glacial outwash deposit and fine-grained interbedded lenses. A two-step geostatistical approach was used to generate a conditioned realization of k representing the bimodal heterogeneity. A cross-sectional multiphase flow model was used to simulate the flow of oil and water in the presence of air along the north pool transect for an 11-year period. The inclusion of a representation of the bimodal aquifer heterogeneity was crucial for reproduction of general features of the observed oil body. If the bimodal heterogeneity was characterized, hysteresis did not have to be incorporated into the model because a hysteretic effect was produced by the sediment spatial variability. By revising the relative permeability functional relation, an improved reproduction of the observed oil saturation distribution was achieved. The inclusion of water table fluctuations in the model did not significantly affect the simulated oil saturation distribution.

  12. Bluebell Field, Uinta Basin: reservoir characterization for improved well completion and oil recovery

    Science.gov (United States)

    Montgomery, S.L.; Morgan, C.D.

    1998-01-01

    Bluefield Field is the largest oil-producing area in the Unita basin of northern Utah. The field inclucdes over 300 wells and has produced 137 Mbbl oil and 177 bcf gas from fractured Paleocene-Eocene lacustrine and fluvial deposits of the Green River and Wasatch (Colton) formations. Oil and gas are produced at depths of 10 500-13 000 ft (3330-3940 m), with the most prolific reservoirs existing in over-pressured sandstones of the Colton Formation and the underlying Flagstaff Member of the lower Green River Formation. Despite a number of high-recovery wells (1-3 MMbbl), overall field recovery remains low, less than 10% original oil in place. This low recovery rate is interpreted to be at least partly a result of completion practices. Typically, 40-120 beds are perforated and stimulated with acid (no proppant) over intervals of up to 3000 ft (900 m). Little or no evaluation of individual beds is performed, preventing identification of good-quality reservoir zones, water-producing zones, and thief zones. As a result, detailed understanding of Bluebell reservoirs historically has been poor, inhibiting any improvements in recovery strategies. A recent project undertaken in Bluebell field as part of the U.S. Department of Energy's Class 1 (fluvial-deltaic reservoir) Oil Demonstration program has focused considerable effort on reservoir characterization. This effort has involved interdisciplinary analysis of core, log, fracture, geostatistical, production, and other data. Much valuable new information on reservoir character has resulted, with important implications for completion techniques and recovery expectations. Such data should have excellent applicability to other producing areas in the Uinta Basin withi reservoirs in similar lacustrine and related deposits.Bluebell field is the largest oil-producing area in the Uinta basin of northern Utah. The field includes over 300 wells and has produced 137 MMbbl oil and 177 bcf gas from fractured Paleocene-Eocene lacustrine

  13. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir, Class I

    Energy Technology Data Exchange (ETDEWEB)

    Bou-Mikael, Sami

    2002-02-05

    This report demonstrates the effectiveness of the CO2 miscible process in Fluvial Dominated Deltaic reservoirs. It also evaluated the use of horizontal CO2 injection wells to improve the overall sweep efficiency. A database of FDD reservoirs for the gulf coast region was developed by LSU, using a screening model developed by Texaco Research Center in Houston. The results of the information gained in this project is disseminated throughout the oil industry via a series of SPE papers and industry open forums.

  14. Molecular processes in the biodegradation of crude oils and crude oil products in the natural reservoir and in laboratory experiments

    International Nuclear Information System (INIS)

    Schalenbach, S.S.

    1993-10-01

    Two ains were pursued in the present study; first, to find positive indicators of the onset of biodegradation of reservoir oil wherever other parameters fail to give a clear picture; second, to establish a basic understanding of the molecular processes underlying the biodegradation of hydrocarbons and thus create a starting point for finding better criteria for valuating biological restoration methods for crude oil contaminated soils. (orig./HS) [de

  15. SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY: APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Matthias G. Imhof; James W. Castle

    2005-02-01

    The objective of the project was to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study focused on West Coalinga Field in California. The project initially attempted to build reservoir models based on different geologic and geophysical data independently using different tools, then to compare the results, and ultimately to integrate them all. We learned, however, that this strategy was impractical. The different data and tools need to be integrated from the beginning because they are all interrelated. This report describes a new approach to geostatistical modeling and presents an integration of geology and geophysics to explain the formation of the complex Coalinga reservoir.

  16. Integration of Seismic and Petrophysics to Characterize Reservoirs in “ALA” Oil Field, Niger Delta

    Directory of Open Access Journals (Sweden)

    P. A. Alao

    2013-01-01

    Full Text Available In the exploration and production business, by far the largest component of geophysical spending is driven by the need to characterize (potential reservoirs. The simple reason is that better reservoir characterization means higher success rates and fewer wells for reservoir exploitation. In this research work, seismic and well log data were integrated in characterizing the reservoirs on “ALA” field in Niger Delta. Three-dimensional seismic data was used to identify the faults and map the horizons. Petrophysical parameters and time-depth structure maps were obtained. Seismic attributes was also employed in characterizing the reservoirs. Seven hydrocarbon-bearing reservoirs with thickness ranging from 9.9 to 71.6 m were delineated. Structural maps of horizons in six wells containing hydrocarbon-bearing zones with tops and bottoms at range of −2,453 to −3,950 m were generated; this portrayed the trapping mechanism to be mainly fault-assisted anticlinal closures. The identified prospective zones have good porosity, permeability, and hydrocarbon saturation. The environments of deposition were identified from log shapes which indicate a transitional-to-deltaic depositional environment. In this research work, new prospects have been recommended for drilling and further research work. Geochemical and biostratigraphic studies should be done to better characterize the reservoirs and reliably interpret the depositional environments.

  17. Integration of seismic and petrophysics to characterize reservoirs in "ALA" oil field, Niger Delta.

    Science.gov (United States)

    Alao, P A; Olabode, S O; Opeloye, S A

    2013-01-01

    In the exploration and production business, by far the largest component of geophysical spending is driven by the need to characterize (potential) reservoirs. The simple reason is that better reservoir characterization means higher success rates and fewer wells for reservoir exploitation. In this research work, seismic and well log data were integrated in characterizing the reservoirs on "ALA" field in Niger Delta. Three-dimensional seismic data was used to identify the faults and map the horizons. Petrophysical parameters and time-depth structure maps were obtained. Seismic attributes was also employed in characterizing the reservoirs. Seven hydrocarbon-bearing reservoirs with thickness ranging from 9.9 to 71.6 m were delineated. Structural maps of horizons in six wells containing hydrocarbon-bearing zones with tops and bottoms at range of -2,453 to -3,950 m were generated; this portrayed the trapping mechanism to be mainly fault-assisted anticlinal closures. The identified prospective zones have good porosity, permeability, and hydrocarbon saturation. The environments of deposition were identified from log shapes which indicate a transitional-to-deltaic depositional environment. In this research work, new prospects have been recommended for drilling and further research work. Geochemical and biostratigraphic studies should be done to better characterize the reservoirs and reliably interpret the depositional environments.

  18. Electrofacies vs. lithofacies sandstone reservoir characterization Campanian sequence, Arshad gas/oil field, Central Sirt Basin, Libya

    Science.gov (United States)

    Burki, Milad; Darwish, Mohamed

    2017-06-01

    The present study focuses on the vertically stacked sandstones of the Arshad Sandstone in Arshad gas/oil field, Central Sirt Basin, Libya, and is based on the conventional cores analysis and wireline log interpretation. Six lithofacies types (F1 to F6) were identified based on the lithology, sedimentary structures and biogenic features, and are supported by wireline log calibration. From which four types (F1-F4) represent the main Campanian sandstone reservoirs in the Arshad gas/oil field. Lithofacies F5 is the basal conglomerates at the lower part of the Arshad sandstones. The Paleozoic Gargaf Formation is represented by lithofacies F6 which is the source provenance for the above lithofacies types. Arshad sediments are interpreted to be deposited in shallow marginal and nearshore marine environment influenced by waves and storms representing interactive shelf to fluvio-marine conditions. The main seal rocks are the Campanian Sirte shale deposited in a major flooding events during sea level rise. It is contended that the syn-depositional tectonics controlled the distribution of the reservoir facies in time and space. In addition, the post-depositional changes controlled the reservoir quality and performance. Petrophysical interpretation from the porosity log values were confirmed by the conventional core measurements of the different sandstone lithofacies types. Porosity ranges from 5 to 20% and permeability is between 0 and 20 mD. Petrophysical cut-off summary of the lower part of the clastic dominated sequence (i. e. Arshad Sandstone) calculated from six wells includes net pay sand ranging from 19.5‧ to 202.05‧, average porosity from 7.7 to 15% and water saturation from 19 to 58%.

  19. Analytical filtration model for nonlinear viscoplastic oil in the theory of oil production stimulation and heating of oil reservoir in a dual-well system

    Science.gov (United States)

    Ivanovich Astafev, Vladimir; Igorevich Gubanov, Sergey; Alexandrovna Olkhovskaya, Valeria; Mikhailovna Sylantyeva, Anastasia; Mikhailovich Zinovyev, Alexey

    2018-02-01

    Production of high-viscosity oil and design of field development systems for such oil is one of the most promising directions in the development of world oil industry. The ability of high-viscosity oil to show in filtration process properties typical for non-Newtonian systems is proven by experimental studies. Nonlinear relationship between the pressure gradient and the rate of oil flow is due to interaction of high-molecular substances, in particular, asphaltenes and tars that form a plastic structure in it. The authors of this article have used the analytical model of stationary influx of nonlinear viscoplastic oil to the well bottom in order to provide rationale for the intensifying impact on a reservoir. They also have analyzed the method of periodic heating of productive reservoir by means of dual-wells. The high-temperature source is placed at the bottom of the vertical well, very close to the reservoir; at the same time the side well, located outside the zone of expected rock damage, is used for production. Suggested method of systemic treatment of reservoirs with dual wells can be useful for small fields of high-viscosity oil. The effect is based on the opportunity to control the structural and mechanical properties of high-viscosity oil and to increase depletion of reserves.

  20. Increasing Heavy Oil in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies. Annual Report, March 30, 1995--March 31, 1996

    International Nuclear Information System (INIS)

    Allison, Edith

    1996-12-01

    The objective of this project is to increase heavy oil reserves in a portion of the Wilmington Oil Field, near Long Beach, California, by implementing advanced reservoir characterization and thermal production technologies. Based on the knowledge and experience gained with this project, these technologies are intended to be extended to other sections of the Wilmington Oil Field, and, through technology transfer, will be available to increase heavy oil reserves in other slope and basin clastic (SBC) reservoirs

  1. Modeling of non-equilibrium effects in solvent-enhanced spontaneous imbibition in fractured reservoirs

    NARCIS (Netherlands)

    Chahardowli, M.; Bruining, J.

    2013-01-01

    In fractured reservoirs, much of the oil is stored in low permeable matrix blocks that are surrounded by a high permeability fracture network. Therefore, production from fractured reservoir depends on the transfer between fracture and matrix, which is critically dependent on their interaction.

  2. Modeling of non-equilibrium effects in solvent-enhanced spontaneous imbibition in fractured reservoirs (poster)

    NARCIS (Netherlands)

    Chahardowli, M.; Bruining, J.

    2013-01-01

    In fractured reservoirs, much of the oil is stored in low permeable matrix blocks that are surrounded by a high permeability fracture network. Therefore, production from fractured reservoir depends on the transfer between fracture and matrix, which is critically dependent on their interaction.

  3. Rhamnolipids Produced by Indigenous Acinetobacter junii from Petroleum Reservoir and its Potential in Enhanced Oil Recovery

    Science.gov (United States)

    Dong, Hao; Xia, Wenjie; Dong, Honghong; She, Yuehui; Zhu, Panfeng; Liang, Kang; Zhang, Zhongzhi; Liang, Chuanfu; Song, Zhaozheng; Sun, Shanshan; Zhang, Guangqing

    2016-01-01

    Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR) processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS). The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C26H48O9, C28H52O9, and C32H58O13. The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR. PMID:27872613

  4. Rhamnolipids produced by indigenous Acinetobacter junii from petroleum reservoir and its potential in enhanced oil recovery

    Directory of Open Access Journals (Sweden)

    Hao Dong

    2016-11-01

    Full Text Available Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS. The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C26H48O9, C28H52O9 and C32H58O13. The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR.

  5. Rhamnolipids Produced by Indigenous Acinetobacter junii from Petroleum Reservoir and its Potential in Enhanced Oil Recovery.

    Science.gov (United States)

    Dong, Hao; Xia, Wenjie; Dong, Honghong; She, Yuehui; Zhu, Panfeng; Liang, Kang; Zhang, Zhongzhi; Liang, Chuanfu; Song, Zhaozheng; Sun, Shanshan; Zhang, Guangqing

    2016-01-01

    Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR) processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS). The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C 26 H 48 O 9 , C 28 H 52 O 9 , and C 32 H 58 O 13 . The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO 3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR.

  6. Study on distribution of reservoir endogenous microbe and oil displacement mechanism

    Directory of Open Access Journals (Sweden)

    Ming Yue

    2017-02-01

    Full Text Available In order to research oil displacement mechanism by indigenous microbial communities under reservoir conditions, indigenous microbial flooding experiments using the endogenous mixed bacterium from Shengli Oilfield were carried out. Through microscopic simulation visual model, observation and analysis of distribution and flow of the remaining oil in the process of water flooding and microbial oil displacement were conducted under high temperature and high pressure conditions. Research has shown that compared with atmospheric conditions, the growth of the microorganism metabolism and attenuation is slowly under high pressure conditions, and the existence of the porous medium for microbial provides good adhesion, also makes its growth cycle extension. The microbial activities can effectively launch all kinds of residual oil, and can together with metabolites, enter the blind holes off which water flooding, polymer flooding and gas flooding can’t sweep, then swap out remaining oil, increase liquidity of the crude oil and remarkably improve oil displacement effect.

  7. ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO

    International Nuclear Information System (INIS)

    Jennie Ridgley

    2000-01-01

    A goal of the Mesaverde project was to better define the depositional system of the Mesaverde in hopes that it would provide insight to new or by-passed targets for oil exploration. The new, detailed studies of the Mesaverde give us a better understanding of the lateral variability in depositional environments and facies. Recognition of this lateral variability and establishment of the criteria for separating deltaic, strandplain-barrier, and estuarine deposits from each other permit development of better hydrocarbon exploration models, because the sandstone geometry differs in each depositional system. Although these insights will provide better exploration models for gas exploration, it does not appear that they will be instrumental in finding more oil. Oil in the Mesaverde Group is produced from isolated fields on the Chaco slope; only a few wells define each field. Production is from sandstone beds in the upper part of the Point Lookout Sandstone or from individual fluvial channel sandstones in the Menefee. Stratigraphic traps rather than structural traps are more important. Source of the oil in the Menefee and Point Lookout may be from interbedded organic-rich mudstones or coals rather than from the Lewis Shale. The Lewis Shale appears to contain more type III organic matter and, hence, should produce mainly gas. Outcrop studies have not documented oil staining that might point to past oil migration through the sandstones of the Mesaverde. The lack of oil production may be related to the following: (1) lack of abundant organic matter of the type I or II variety in the Lewis Shale needed to produce oil, (2) ineffective migration pathways due to discontinuities in sandstone reservoir geometries, (3) cementation or early formation of gas prior to oil generation that reduced effective permeabilities and served as barriers to updip migration of oil, or (4) erosion of oilbearing reservoirs from the southern part of the basin. Any new production should mimic that of

  8. Oil Reservoir Production Optimization using Single Shooting and ESDIRK Methods

    DEFF Research Database (Denmark)

    Capolei, Andrea; Völcker, Carsten; Frydendall, Jan

    2012-01-01

    the injections and oil production such that flow is uniform in a given geological structure. Even in the case of conventional water flooding, feedback based optimal control technologies may enable higher oil recovery than with conventional operational strategies. The optimal control problems that must be solved...

  9. Use of modified nanoparticles in oil and gas reservoir management

    NARCIS (Netherlands)

    Turkenburg, D.H.; Chin, P.T.K.; Fischer, H.R.

    2012-01-01

    We describe a water dispersed nano sensor cocktail based on InP/ZnS quantum dots (QDs) and atomic silver clusters with a bright and visible luminescence combined with optimized sensor functionalities for the water flooding process. The QDs and Ag nano sensors were tested in simulated reservoir

  10. An improved method for predicting brittleness of rocks via well logs in tight oil reservoirs

    Science.gov (United States)

    Wang, Zhenlin; Sun, Ting; Feng, Cheng; Wang, Wei; Han, Chuang

    2018-06-01

    There can be no industrial oil production in tight oil reservoirs until fracturing is undertaken. Under such conditions, the brittleness of the rocks is a very important factor. However, it has so far been difficult to predict. In this paper, the selected study area is the tight oil reservoirs in Lucaogou formation, Permian, Jimusaer sag, Junggar basin. According to the transformation of dynamic and static rock mechanics parameters and the correction of confining pressure, an improved method is proposed for quantitatively predicting the brittleness of rocks via well logs in tight oil reservoirs. First, 19 typical tight oil core samples are selected in the study area. Their static Young’s modulus, static Poisson’s ratio and petrophysical parameters are measured. In addition, the static brittleness indices of four other tight oil cores are measured under different confining pressure conditions. Second, the dynamic Young’s modulus, Poisson’s ratio and brittleness index are calculated using the compressional and shear wave velocity. With combination of the measured and calculated results, the transformation model of dynamic and static brittleness index is built based on the influence of porosity and clay content. The comparison of the predicted brittleness indices and measured results shows that the model has high accuracy. Third, on the basis of the experimental data under different confining pressure conditions, the amplifying factor of brittleness index is proposed to correct for the influence of confining pressure on the brittleness index. Finally, the above improved models are applied to formation evaluation via well logs. Compared with the results before correction, the results of the improved models agree better with the experimental data, which indicates that the improved models have better application effects. The brittleness index prediction method of tight oil reservoirs is improved in this research. It is of great importance in the optimization of

  11. A Reduced Order Model for Fast Production Prediction from an Oil Reservoir with a Gas Cap

    OpenAIRE

    Yang, Yichen

    2016-01-01

    Master's thesis in Petroleum geosciences engineering Economic evaluations are essential inputs for oil and gas field development decisions. These evaluations are critically dependent on the unbiased assessment of uncertainty in the future oil and gas production from wells. However, many production prediction techniques come at significant computational costs as they often require a very large number of highly detailed grid based reservoir simulations. In this study, we present an alter...

  12. Bioaugmentation of oil reservoir indigenous Pseudomonas aeruginosa to enhance oil recovery through in-situ biosurfactant production without air injection.

    Science.gov (United States)

    Zhao, Feng; Li, Ping; Guo, Chao; Shi, Rong-Jiu; Zhang, Ying

    2018-03-01

    Considering the anoxic conditions within oil reservoirs, a new microbial enhanced oil recovery (MEOR) technology through in-situ biosurfactant production without air injection was proposed. High-throughput sequencing data revealed that Pseudomonas was one of dominant genera in Daqing oil reservoirs. Pseudomonas aeruginosa DQ3 which can anaerobically produce biosurfactant at 42 °C was isolated. Strain DQ3 was bioaugmented in an anaerobic bioreactor to approximately simulate MEOR process. During bioaugmentation process, although a new bacterial community was gradually formed, Pseudomonas was still one of dominant genera. Culture-based data showed that hydrocarbon-degrading bacteria and biosurfactant-producing bacteria were activated, while sulfate reducing bacteria were controlled. Biosurfactant was produced at simulated reservoir conditions, decreasing surface tension to 33.8 mN/m and emulsifying crude oil with EI 24  = 58%. Core flooding tests revealed that extra 5.22% of oil was displaced by in-situ biosurfactant production. Bioaugmenting indigenous biosurfactant producer P. aeruginosa without air injection is promising for in-situ MEOR applications. Copyright © 2017 Elsevier Ltd. All rights reserved.

  13. Electrokinetic effects and fluid permeability

    International Nuclear Information System (INIS)

    Berryman, J.G.

    2003-01-01

    Fluid permeability of porous media depends mainly on connectivity of the pore space and two physical parameters: porosity and a pertinent length-scale parameter. Electrical imaging methods typically establish connectivity and directly measure electrical conductivity, which can then often be related to porosity by Archie's law. When electrical phase measurements are made in addition to the amplitude measurements, information about the pertinent length scale can then be obtained. Since fluid permeability controls the ability to flush unwanted fluid contaminants from the subsurface, inexpensive maps of permeability could improve planning strategies for remediation efforts. Detailed knowledge of fluid permeability is also important for oil field exploitation, where knowledge of permeability distribution in three dimensions is a common requirement for petroleum reservoir simulation and analysis, as well as for estimates on the economics of recovery

  14. Isolation of Biosurfactant Producing Bacteria from Oil Reservoirs

    OpenAIRE

    A Tabatabaee, M Mazaheri Assadi, AA Noohi,VA Sajadian

    2005-01-01

    Biosurfactants or surface-active compounds are produced by microoaganisms. These molecules reduce surface tension both aqueous solutions and hydrocarbon mixtures. In this study, isolation and identification of biosurfactant producing bacteria were assessed. The potential application of these bacteria in petroleum industry was investigated. Samples (crude oil) were collected from oil wells and 45 strains were isolated. To confirm the ability of isolates in biosurfactant production, haemolysis ...

  15. Process for selectivity lowering the water permeability of a crude oil deposit

    Energy Technology Data Exchange (ETDEWEB)

    Katser, M F

    1966-10-20

    In this process for selectively reducing the water permeability of oil-bearing formations, especially during waterflooding, an aqueous solution is injected into the producing well. This solution contains a hydrolyzed acryl amide polymer, polyacrylamide or a copolymer, the greater part of which is acrylamide and the smaller part a polymerizable monomer, e.g., vinyl alcohol, vinyl chloride, acrylonitrile, methacrylonitrile or vinyl acryl ether. About 0.5-67.0% of the carboxy amide groups of the acrylamide polymer are hydrolyzed to carboxilic groups. The concentration of the hydrolyzed acrylamide polymer in the solution is about 0.01-1.0%. (3 claims)

  16. A combination of streamtube and geostatical simulation methodologies for the study of large oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Chakravarty, A.; Emanuel, A.S.; Bernath, J.A. [Chevron Petroleum Technology Company, LaHabra, CA (United States)

    1997-08-01

    The application of streamtube models for reservoir simulation has an extensive history in the oil industry. Although these models are strictly applicable only to fields under voidage balance, they have proved to be useful in a large number of fields provided that there is no solution gas evolution and production. These models combine the benefit of very fast computational time with the practical ability to model a large reservoir over the course of its history. These models do not, however, directly incorporate the detailed geological information that recent experience has taught is important. This paper presents a technique for mapping the saturation information contained in a history matched streamtube model onto a detailed geostatistically derived finite difference grid. With this technique, the saturation information in a streamtube model, data that is actually statistical in nature, can be identified with actual physical locations in a field and a picture of the remaining oil saturation can be determined. Alternatively, the streamtube model can be used to simulate the early development history of a field and the saturation data then used to initialize detailed late time finite difference models. The proposed method is presented through an example application to the Ninian reservoir. This reservoir, located in the North Sea (UK), is a heterogeneous sandstone characterized by a line drive waterflood, with about 160 wells, and a 16 year history. The reservoir was satisfactorily history matched and mapped for remaining oil saturation. A comparison to 3-D seismic survey and recently drilled wells have provided preliminary verification.

  17. Letting Off Steam and Getting Into Hot Water - Harnessing the Geothermal Energy Potential of Heavy Oil Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Teodoriu, Catalin; Falcone, Gioia; Espinel, Arnaldo

    2007-07-01

    The oil industry is turning its attention to the more complex development of heavy oil fields in order to meet the ever increasing demands of the manufacturing sector. The current thermal recovery techniques of heavy oil developments provide an opportunity to benefit from the geothermal energy created during the heavy oil production process. There is scope to improve the current recovery factors of heavy oil reservoirs, and there is a need to investigate the associated geothermal energy potential that has been historically neglected. This paper presents a new concept of harnessing the geothermal energy potential of heavy oil reservoirs with the co-production of incremental reserves. (auth)

  18. Sequence Stratigraphic Framework Analysis of Putaohua Oil Reservoir in Chaochang Area of Songliao Basin

    Science.gov (United States)

    Chang, Yan; Liu, Dameng; Yao, Yanbin

    2018-01-01

    The regional structure of the Changchang area in the Songliao Basin is located on the Chaoyangou terrace and Changchunling anticline belt in the central depression of the northern part of the Songliao Basin, across the two secondary tectonic units of the Chaoyanggou terrace and Changchunling anticline. However, with the continuous development of oil and gas, the unused reserves of Fuyu oil reservoir decreased year by year, and the oil field faced a serious shortage of reserve reserves. At the same time, during the evaluation process, a better oil-bearing display was found during the drilling and test oil in the Putao depression to the Chaoyanggou terraces, the Yudong-Taipingchuan area, and in the process of drilling and testing oil in the Putaohua reservoir. Zhao41, Zhao18-1, Shu38 and other exploration wells to obtain oil oil, indicating that the area has a further evaluation of the potential. Based on the principle of stratification, the Putao area was divided into three parts by using the core, logging and logging. It is concluded that the middle and western strata of the study area are well developed, including three sequences, one cycle from bottom to top (three small layers), two cycles (one small layer), three cycles (two small layers) Rhythm is positive-anti-positive. From the Midwest to the southeastern part of the strata, the strata are overtaken, the lower strata are missing, and the top rhythms become rhythmic.

  19. An adaptive robust optimization scheme for water-flooding optimization in oil reservoirs using residual analysis

    NARCIS (Netherlands)

    Siraj, M.M.; Van den Hof, P.M.J.; Jansen, J.D.

    2017-01-01

    Model-based dynamic optimization of the water-flooding process in oil reservoirs is a computationally complex problem and suffers from high levels of uncertainty. A traditional way of quantifying uncertainty in robust water-flooding optimization is by considering an ensemble of uncertain model

  20. A strategy for low cost development of incremental oil in legacy reservoirs

    Science.gov (United States)

    Attanasi, E.D.

    2016-01-01

    The precipitous decline in oil prices during 2015 has forced operators to search for ways to develop low-cost and low-risk oil reserves. This study examines strategies to low cost development of legacy reservoirs, particularly those which have already implemented a carbon dioxide enhanced oil recovery (CO2 EOR) program. Initially the study examines the occurrence and nature of the distribution of the oil resources that are targets for miscible and near-miscible CO2 EOR programs. The analysis then examines determinants of technical recovery through the analysis of representative clastic and carbonate reservoirs. The economic analysis focusses on delineating the dominant components of investment and operational costs. The concluding sections describe options to maximize the value of assets that the operator of such a legacy reservoir may have that include incremental expansion within the same producing zone and to producing zones that are laterally or stratigraphically near main producing zones. The analysis identified the CO2 recycle plant as the dominant investment cost item and purchased CO2 and liquids management as a dominant operational cost items. Strategies to utilize recycle plants for processing CO2 from multiple producing zones and multiple reservoir units can significantly reduce costs. Industrial sources for CO2 should be investigated as a possibly less costly way of meeting EOR requirements. Implementation of tapered water alternating gas injection schemes can partially mitigate increases in fluid lifting costs.

  1. On an inverse source problem for enhanced oil recovery by wave motion maximization in reservoirs

    KAUST Repository

    Karve, Pranav M.; Kucukcoban, Sezgin; Kallivokas, Loukas F.

    2014-01-01

    to increase the mobility of otherwise entrapped oil. The goal is to arrive at the spatial and temporal description of surface sources that are capable of maximizing mobility in the target reservoir. The focusing problem is posed as an inverse source problem

  2. Experimental and Theoretical Determination of Heavy Oil Viscosity Under Reservoir Conditions; ANNUAL

    International Nuclear Information System (INIS)

    Gabitto, Jorge; Barrufet, Maria

    2002-01-01

    The main objective of this research was to propose a simple procedure to predict heavy oil viscosity at reservoir conditions as a function of easily determined physical properties. This procedure will avoid costly experimental testing and reduce uncertainty in designing thermal recovery processes

  3. Research of hard-to-recovery and unconventional oil-bearing formations according to the principle «in-situ reservoir fabric»

    Directory of Open Access Journals (Sweden)

    А. Д. Алексеев

    2017-12-01

    Full Text Available Currently in Russia and the world due to the depletion of old highly productive deposits, the role of hard-to-recover and unconventional hydrocarbons is increasing. Thanks to scientific and technical progress, it became possible to involve in the development very low permeable reservoirs and even synthesize oil and gas in-situ. Today, wells serve not only for the production of hydrocarbons, but also are important elements of stimulation technology, through which the technogenic effect on the formation is carried out in order to intensify inflows. In this context, the reservoir itself can be considered as a raw material for the application of stimulation technologies, and the set of wells through which it is technologically affected is a plant or a fabric whose intermediate product is the stimulated zone of the formation and the final product is reservoir hydrocarbons. Well-established methods for studying hydrocarbon deposits are limited to the definition of standard geological parameters, which are commonly used for reserves calculations (net pay, porosity, permeability, oil and gas saturation coefficient, area, but they are clearly insufficient to characterize the development possibilities using modern stimulation technologies. To study objects that are promising for the production of hydrocarbons, it is necessary to develop fundamentally new approaches that make it possible to assess the availability of resources depending on the technologies used, and to improve the methods for forecasting and evaluating the properties of the stimulated zone of the formation. «In-situ reservoir fabric» is a collective term that combines a combination of technologies, research and methodological approaches aimed at creating and evaluating a stimulated zone of the formation by applying modern methods of technogenic impact on objects containing hard-to-recover and «unconventional» hydrocarbons in order to intensify inflows from them hydrocarbons. In 2015

  4. Radionuclide Migration at the Rio Blanco Site, A Nuclear-stimulated Low-permeability Natural Gas Reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Clay A. Cooper; Ming Ye; Jenny Chapman; Craig Shirley

    2005-10-01

    The U.S. Department of Energy and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of low-permeability gas reservoirs. The third and final project in the program, Project Rio Blanco, was conducted in Rio Blanco County, in northwestern Colorado. In this experiment, three 33-kiloton nuclear explosives were simultaneously detonated in a single emplacement well in the Mesaverde Group and Fort Union Formation, at depths of 1,780, 1,899, and 2,039 m below land surface on May 17, 1973. The objective of this work is to estimate lateral distances that tritium released from the detonations may have traveled in the subsurface and evaluate the possible effect of postulated natural-gas development on radionuclide migration. Other radionuclides were considered in the analysis, but the majority occur in relatively immobile forms (such as nuclear melt glass). Of the radionuclides present in the gas phase, tritium dominates in terms of quantity of radioactivity in the long term and contribution to possible whole body exposure. One simulation is performed for {sup 85}Kr, the second most abundant gaseous radionuclide produced after tritium.

  5. Profiles of Reservoir Properties of Oil-Bearing Plays for Selected Petroleum Provinces in the United States

    Science.gov (United States)

    Freeman, P.A.; Attanasi, E.D.

    2015-11-05

    Profiles of reservoir properties of oil-bearing plays for selected petroleum provinces in the United States were developed to characterize the database to be used for a potential assessment by the U.S. Geological Survey (USGS) of oil that would be technically recoverable by the application of enhanced oil recovery methods using injection of carbon dioxide (CO2-EOR). The USGS assessment methodology may require reservoir-level data for the purposes of screening conventional oil reservoirs and projecting CO2-EOR performance in terms of the incremental recoverable oil. The information used in this report is based on reservoir properties from the “Significant Oil and Gas Fields of the United States Database” prepared by Nehring Associates, Inc. (2012). As described by Nehring Associates, Inc., the database “covers all producing provinces (basins) in the United States except the Appalachian Basin and the Cincinnati Arch.”

  6. Maximization of wave motion within a hydrocarbon reservoir for wave-based enhanced oil recovery

    KAUST Repository

    Jeong, C.

    2015-05-01

    © 2015 Elsevier B.V. We discuss a systematic methodology for investigating the feasibility of mobilizing oil droplets trapped within the pore space of a target reservoir region by optimally directing wave energy to the region of interest. The motivation stems from field and laboratory observations, which have provided sufficient evidence suggesting that wave-based reservoir stimulation could lead to economically viable oil recovery.Using controlled active surface wave sources, we first describe the mathematical framework necessary for identifying optimal wave source signals that can maximize a desired motion metric (kinetic energy, particle acceleration, etc.) at the target region of interest. We use the apparatus of partial-differential-equation (PDE)-constrained optimization to formulate the associated inverse-source problem, and deploy state-of-the-art numerical wave simulation tools to resolve numerically the associated discrete inverse problem.Numerical experiments with a synthetic subsurface model featuring a shallow reservoir show that the optimizer converges to wave source signals capable of maximizing the motion within the reservoir. The spectra of the wave sources are dominated by the amplification frequencies of the formation. We also show that wave energy could be focused within the target reservoir area, while simultaneously minimizing the disturbance to neighboring formations - a concept that can also be exploited in fracking operations.Lastly, we compare the results of our numerical experiments conducted at the reservoir scale, with results obtained from semi-analytical studies at the granular level, to conclude that, in the case of shallow targets, the optimized wave sources are likely to mobilize trapped oil droplets, and thus enhance oil recovery.

  7. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    International Nuclear Information System (INIS)

    Green, Don W.; McCune, A.D.; Michnick, M.; Reynolds, R.; Walton, A.; Watney, L.; Willhite, G. Paul

    1999-01-01

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and in Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by PetroSantander, Inc. Te Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. In the Stewart Project, the reservoir management portion of the project conducted during Budget Period 1 involved performance evaluation. This included (1) reservoir characterization and the development of a reservoir database, (2) volumetric analysis to evaluate production performance, (3) reservoir modeling, (4) laboratory work, (5) identification of operational problems, (6) identification of unrecovered mobile oil and estimation of recovery factors, and (7) Identification of the most efficient and economical recovery process. To accomplish these objectives the initial budget period was subdivided into three major tasks. The tasks were (1) geological and engineering analysis, (2) laboratory testing, and (3) unitization. Due to the presence of different operators within the field, it was necessary to unitize the field in order to demonstrate a field-wide improved recovery process. This work was completed and the project moved into Budget Period 2

  8. Flow behavior of N2 huff and puff process for enhanced oil recovery in tight oil reservoirs.

    Science.gov (United States)

    Lu, Teng; Li, Zhaomin; Li, Jian; Hou, Dawei; Zhang, Dingyong

    2017-11-16

    In the present work, the potential of N 2 huff and puff process to enhance the recovery of tight oil reservoir was evaluated. N 2 huff and puff experiments were performed in micromodels and cores to investigate the flow behaviors of different cycles. The results showed that, in the first cycle, N 2 was dispersed in the oil, forming the foamy oil flow. In the second cycle, the dispersed gas bubbles gradually coalesced into the continuous gas phase. In the third cycle, N 2 was produced in the form of continuous gas phase. The results from the coreflood tests showed that, the primary recovery was only 5.32%, while the recoveries for the three N 2 huff and puff cycles were 15.1%, 8.53% and 3.22%, respectively.The recovery and the pressure gradient in the first cycle were high. With the increase of huff and puff cycles, and the oil recovery and the pressure gradient rapidly decreased. The oil recovery of N 2 huff and puff has been found to increase as the N 2 injection pressure and the soaking time increased. These results showed that, the properly designed and controlled N 2 huff and puff process can lead to enhanced recovery of tight oil reservoirs.

  9. Performance of Surfactant Methyl Ester Sulphonate solution for Oil Well Stimulation in reservoir sandstone TJ Field

    Science.gov (United States)

    Eris, F. R.; Hambali, E.; Suryani, A.; Permadi, P.

    2017-05-01

    Asphaltene, paraffin, wax and sludge deposition, emulsion and water blocking are kinds ofprocess that results in a reduction of the fluid flow from the reservoir into formation which causes a decrease of oil wells productivity. Oil well Stimulation can be used as an alternative to solve oil well problems. Oil well stimulation technique requires applying of surfactant. Sodium Methyl Ester Sulphonate (SMES) of palm oil is an anionic surfactant derived from renewable natural resource that environmental friendly is one of potential surfactant types that can be used in oil well stimulation. This study was aimed at formulation SMES as well stimulation agent that can identify phase transitions to phase behavior in a brine-surfactant-oil system and altered the wettability of rock sandstone and limestone. Performance of SMES solution tested by thermal stability test, phase behavioral examination and rocks wettability test. The results showed that SMES solution (SMES 5% + xylene 5% in the diesel with addition of 1% NaCl at TJformation water and SMES 5% + xylene 5% in methyl ester with the addition of NaCl 1% in the TJ formation water) are surfactant that can maintain thermal stability, can mostly altered the wettability toward water-wet in sandstone reservoir, TJ Field.

  10. Investigation of spore forming bacterial flooding for enhanced oil recovery in a North Sea chalk Reservoir

    DEFF Research Database (Denmark)

    Halim, Amalia Yunita; Nielsen, Sidsel Marie; Eliasson Lantz, Anna

    2015-01-01

    Little has been done to study microbial enhanced oil recovery (MEOR) in chalk reservoirs. The present study focuses on core flooding experiments designed to see microbial plugging and its effect on oil recovery. A pressure tapped core holder was used for this purpose. A spore forming bacteria...... Bacillus licheniformis 421 was used as it was shown to be a good candidate in a previous study. Bacterial spore can penetrate deeper into the chalk rock, squeezing through the pore throats. Our results showed that injection of B. licheniformis 421 as a tertiary oil recovery method, in the residual oil...... saturation state, was able to produce additionally 1.0-2.3% original oil in place (OOIP) in homogeneous cores and 6.9-8.8% OOIP in heterogeneous cores. In addition, the pressure gradient was much higher in the heterogeneous cores, which confirms that bacterial selective plugging plays an important role...

  11. Terahertz-dependent identification of simulated hole shapes in oil-gas reservoirs

    Science.gov (United States)

    Bao, Ri-Ma; Zhan, Hong-Lei; Miao, Xin-Yang; Zhao, Kun; Feng, Cheng-Jing; Dong, Chen; Li, Yi-Zhang; Xiao, Li-Zhi

    2016-10-01

    Detecting holes in oil-gas reservoirs is vital to the evaluation of reservoir potential. The main objective of this study is to demonstrate the feasibility of identifying general micro-hole shapes, including triangular, circular, and square shapes, in oil-gas reservoirs by adopting terahertz time-domain spectroscopy (THz-TDS). We evaluate the THz absorption responses of punched silicon (Si) wafers having micro-holes with sizes of 20 μm-500 μm. Principal component analysis (PCA) is used to establish a model between THz absorbance and hole shapes. The positions of samples in three-dimensional spaces for three principal components are used to determine the differences among diverse hole shapes and the homogeneity of similar shapes. In addition, a new Si wafer with the unknown hole shapes, including triangular, circular, and square, can be qualitatively identified by combining THz-TDS and PCA. Therefore, the combination of THz-TDS with mathematical statistical methods can serve as an effective approach to the rapid identification of micro-hole shapes in oil-gas reservoirs. Project supported by the National Natural Science Foundation of China (Grant No. 61405259), the National Basic Research Program of China (Grant No. 2014CB744302), and the Specially Founded Program on National Key Scientific Instruments and Equipment Development, China (Grant No. 2012YQ140005).

  12. Productivity Analysis of Volume Fractured Vertical Well Model in Tight Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Jiahang Wang

    2017-01-01

    Full Text Available This paper presents a semianalytical model to simulate the productivity of a volume fractured vertical well in tight oil reservoirs. In the proposed model, the reservoir is a composite system which contains two regions. The inner region is described as formation with finite conductivity hydraulic fracture network and the flow in fracture is assumed to be linear, while the outer region is simulated by the classical Warren-Root model where radial flow is applied. The transient rate is calculated, and flow patterns and characteristic flowing periods caused by volume fractured vertical well are analyzed. Combining the calculated results with actual production data at the decline stage shows a good fitting performance. Finally, the effects of some sensitive parameters on the type curves are also analyzed extensively. The results demonstrate that the effect of fracture length is more obvious than that of fracture conductivity on improving production in tight oil reservoirs. When the length and conductivity of main fracture are constant, the contribution of stimulated reservoir volume (SRV to the cumulative oil production is not obvious. When the SRV is constant, the length of fracture should also be increased so as to improve the fracture penetration and well production.

  13. The influence of lumping on the behavior of reservoir with light oil and CO2

    Energy Technology Data Exchange (ETDEWEB)

    Scanavini, Helena Finardi Alvares [Universidade Estadual de Campinas (UNISIM/UNICAMP), SP (Brazil). Dept. de Engenharia de Petroleo. Pesquisa em Simulacao e Gerenciamento de Reservatorios; Schiozer, Denis Jose [Universidade Estadual de Campinas (DEP/FEM/UNICAMP), SP (Brazil). Fac. de Engenharia Mecanica. Dept. de Engenharia de Petroleo

    2012-07-01

    Compositional simulation demands a large number of equations and functions to be solved, once fluid properties depend on reservoir pressure and temperature and also on fluid composition. As a consequence, the number of components used influences considerably in the simulation run time and accuracy: more components yield more equations to be solved with expected higher run time. Giant petroleum fields discovered recently in Brazil (pre-salt reservoirs) demand compositional simulation due to the fluid characteristics (light oil with the presence of CO2). However, the computational time can be a limitation because of the number of grid blocks that are necessary to represent the reservoir. So, reducing the number of components is an important step for the simulation models. Under this context, this paper presents a study on the influence of different lumping clusters, used to reduce the number of components in a volatile oil, on reservoir simulation. Phase diagram, saturation pressure and simulation results were used for comparison purposes. The best results were obtained for the cases with 14, 9 and 7 pseudo components, which represented correctly the original fluid, reducing till three times the simulation run time, for the same production volumes of oil and gas. (author)

  14. Oil-water flows in wells with powerful fracture reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Ivanov, N.P.

    1979-01-01

    The character of two phase liquid flows from powerful layer fractures to bottom holes in Starogrodnen and Malgobek-Voznesenskiy fields in the Chechen-Ingush ASSR found in the late stage of operation. The studies were done with the electrothermometer TEG-36, the manometer MGN-2, the remote control thermal flow meter T-4, the remote control moisture meter VBST-1, the density meter GGP-1M, whose accuracy class is 1.0 and whose working limits are: temperature, up to 150/sup 0/C and pressure, up to 1000 kGs/cm/sup 2/. The breakdown of the linear filtration law and the gravitational division of the water-oil mixture phase occurred during fieldwork. The oil and water, etc., flow intervals were defined. The data from the moisture meter and the gamma density meter coincided.

  15. Utilizing natural gas huff and puff to enhance production in heavy oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Wenlong, G.; Shuhong, W.; Jian, Z.; Xialin, Z. [Society of Petroleum Engineers, Kuala Lumpur (Malaysia)]|[PetroChina Co. Ltd., Beijing (China); Jinzhong, L.; Xiao, M. [China Univ. of Petroleum, Beijing (China)

    2008-10-15

    The L Block in the north structural belt of China's Tuha Basin is a super deep heavy oil reservoir. The gas to oil ratio (GOR) is 12 m{sup 3}/m{sup 3} and the initial bubble point pressure is only 4 MPa. The low production can be attributed to high oil viscosity and low flowability. Although steam injection is the most widely method for heavy oil production in China, it is not suitable for the L Block because of its depth. This paper reviewed pilot tests in which the natural gas huff and puff process was used to enhance production in the L Block. Laboratory experiments that included both conventional and unconventional PVT were conducted to determine the physical property of heavy oil saturated by natural gas. The experiments revealed that the heavy oil can entrap the gas for more than several hours because of its high viscosity. A pseudo bubble point pressure exists much lower than the bubble point pressure in manmade foamy oils, which is relative to the depressurization rate. Elastic energy could be maintained in a wider pressure scope than natural depletion without gas injection. A special experimental apparatus that can stimulate the process of gas huff and puff in the reservoir was also introduced. The foamy oil could be seen during the huff and puff experiment. Most of the oil flowed to the producer in a pseudo single phase, which is among the most important mechanisms for enhancing production. A pilot test of a single well demonstrated that the oil production increased from 1 to 2 cubic metres per day to 5 to 6 cubic metres per day via the natural gas huff and puff process. The stable production period which was 5 to 10 days prior to huff and puff, was prolonged to 91 days in the first cycle and 245 days in the second cycle. 10 refs., 1 tab., 12 figs.

  16. Isolation of Biosurfactant Producing Bacteria from Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    A Tabatabaee, M Mazaheri Assadi, AA Noohi,VA Sajadian

    2005-01-01

    Full Text Available Biosurfactants or surface-active compounds are produced by microoaganisms. These molecules reduce surface tension both aqueous solutions and hydrocarbon mixtures. In this study, isolation and identification of biosurfactant producing bacteria were assessed. The potential application of these bacteria in petroleum industry was investigated. Samples (crude oil were collected from oil wells and 45 strains were isolated. To confirm the ability of isolates in biosurfactant production, haemolysis test, emulsification test and measurement of surface tension were conducted. We also evaluated the effect of different pH, salinity concentrations, and temperatures on biosurfactant production. Among importance features of the isolated strains, one of the strains (NO.4: Bacillus.sp showed high salt tolerance and their successful production of biosurfactant in a vast pH and temperature domain and reduced surface tension to value below 40 mN/m. This strain is potential candidate for microbial enhanced oil recovery. The strain4 biosurfactant component was mainly glycolipid in nature.

  17. Digital Core Modelling for Clastic Oil and Gas Reservoir

    Science.gov (United States)

    Belozerov, I.; Berezovsky, V.; Gubaydullin, M.; Yur’ev, A.

    2018-05-01

    "Digital core" is a multi-purpose tool for solving a variety of tasks in the field of geological exploration and production of hydrocarbons at various stages, designed to improve the accuracy of geological study of subsurface resources, the efficiency of reproduction and use of mineral resources, as well as applying the results obtained in production practice. The actuality of the development of the "Digital core" software is that even a partial replacement of natural laboratory experiments with mathematical modelling can be used in the operative calculation of reserves in exploratory drilling, as well as in the absence of core material from wells. Or impossibility of its research by existing laboratory methods (weakly cemented, loose, etc. rocks). 3D-reconstruction of the core microstructure can be considered as a cheap and least time-consuming method for obtaining petrophysical information about the main filtration-capacitive properties and fluid motion in reservoir rocks.

  18. Investigation of biosurfactant-producing indigenous microorganisms that enhance residue oil recovery in an oil reservoir after polymer flooding.

    Science.gov (United States)

    She, Yue-Hui; Zhang, Fan; Xia, Jing-Jing; Kong, Shu-Qiong; Wang, Zheng-Liang; Shu, Fu-Chang; Hu, Ji-Ming

    2011-01-01

    Three biosurfactant-producing indigenous microorganisms (XDS1, XDS2, XDS3) were isolated from a petroleum reservoir in the Daqing Oilfield (China) after polymer flooding. Their metabolic, biochemical, and oil-degradation characteristics, as well as their oil displacement in the core were studied. These indigenous microorganisms were identified as short rod bacillus bacteria with white color, round shape, a protruding structure, and a rough surface. Strains have peritrichous flagella, are able to produce endospores, are sporangia, and are clearly swollen and terminal. Bacterial cultures show that the oil-spreading values of the fermentation fluid containing all three strains are more than 4.5 cm (diameter) with an approximate 25 mN/m surface tension. The hydrocarbon degradation rates of each of the three strains exceeded 50%, with the highest achieving 84%. Several oil recovery agents were produced following degradation. At the same time, the heavy components of crude oil were degraded into light components, and their flow characteristics were also improved. The surface tension and viscosity of the crude oil decreased after being treated by the three strains of microorganisms. The core-flooding tests showed that the incremental oil recoveries were 4.89-6.96%. Thus, XDS123 treatment may represent a viable method for microbial-enhanced oil recovery.

  19. Environmental drivers of differences in microbial community structure in crude oil reservoirs across a methanogenic gradient

    Directory of Open Access Journals (Sweden)

    Jenna L Shelton

    2016-09-01

    Full Text Available Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow up-dip wells was different than the 17 deeper, down-dip wells, and that

  20. Characterization of oil and gas reservoir heterogeneity. Annual report, November 1, 1990--October 31, 1991

    Energy Technology Data Exchange (ETDEWEB)

    1991-12-31

    The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

  1. Potential application of oxygen containing gases to enhance gravity drainage in heavy oil bearing reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Lakatos, I. [Hungarian Academy of Sciences, Miscolc (Hungary). Lab. for Mining Chemistry; Bauer, K. [Hungarian Academy of Sciences, Miscolc (Hungary). Lab. for Mining Chemistry; Lakatos-Szabo, J. [Hungarian Academy of Sciences, Miscolc (Hungary). Lab. for Mining Chemistry

    1997-06-01

    In the frame of laboratory studies the effect of air/natural CO{sub 2} mixtures on chemical composition of crude oil and gas phase, the rheological and interfacial properties, the flow mechanism and the safety measures were analyzed. The tests were performed at reservoir conditions (200 bar and 109 C) using natural rock, oil and gas samples. The oxygen content of the gas phase and the gas/oil ratio varied within wide limits. Both crude and asphaltene-free oil were used to determine the consequences of the low temperature oxidation. On the basis of the experimental results it was found that the oxygen content of the cap gas had been completely consumed by the chemical reactions (oxidation, condensation and water formation) before the asphaltene content set in equilibrium. Nearly 9% excess asphaltene formation was observed in both the crude and the asphaltene-free oils. The substantial increase in asphaltene content and the presence of colloidal water results in a measurable change in rheological and interfacial properties. Despite these factors the flow and displacement mechanism is only slightly influenced if the reservoir is of fractured character. On the other hand the in-situ oxidation of this heavy crude oil improves the efficiency of bitumen production and the quality of product used mostly for road construction. As a final statement, it was concluded that replacing the CO{sub 2} with oxygen containing inert gas, the chemical reactions can be in-situ regulated without jeopardizing the recovery efficiency. Application of the artificial gas cap concept opens new perspectives in EOR technology of karstic and fractured reservoirs containing medium and heavy crude oils in those cases where CO{sub 2} or CH gas is not available. (orig./MSK)

  2. Synthesis of radiolabelled organic compounds for use as water tracers in oil reservoirs

    International Nuclear Information System (INIS)

    Eriksen, D.Oe.; Bjoernstad, V.

    1999-01-01

    Injection of water into oil containing strata to maintain field pressure and to replace oil is usually the primary choice to enhance oil-recovery. Use of tracer methods is becoming an important part of the oil companies' basis for making economical decisions. Such water tracing requires passive tracers, i.e. compounds that behave exactly like the substance studied under the conditions of interest. This implies that a water-tracer in a water-flooded oil-field must fulfil requirements like no absorption to reservoir rock, no partitioning (or distribution) with respect to the other fluids present, long time thermal stability, microbial resistance and high detectability. In addition, the tracer compound has to be environmentally acceptable and available at a reasonable cost. Among the extensive number of compounds tested according to these criteria in the laboratory we have qualified four compounds as tracers for water in oil reservoirs. For three of them we propose radiolabelling syntheses with 14 C as radioactive label to lower detection limits. The compounds are benzene 1,2- and 1,3-dicarboxylic acids and benzene 1,3,5-tricarboxylic acid. (author)

  3. Activation of CO2-reducing methanogens in oil reservoir after addition of nutrient.

    Science.gov (United States)

    Yang, Guang-Chao; Zhou, Lei; Mbadinga, Serge Maurice; You, Jing; Yang, Hua-Zhen; Liu, Jin-Feng; Yang, Shi-Zhong; Gu, Ji-Dong; Mu, Bo-Zhong

    2016-12-01

    Nutrient addition as part of microbial enhanced oil recovery (MEOR) operations have important implications for more energy recovery from oil reservoirs, but very little is known about the in situ response of microorganisms after intervention. An analysis of two genes as biomarkers, mcrA encoding the key enzyme in methanogenesis and fthfs encoding the key enzyme in acetogenesis, was conducted during nutrient addition in oil reservoir. Clone library data showed that dominant mcrA sequences changed from acetoclastic (Methanosaetaceae) to CO 2 -reducing methanogens (Methanomicrobiales and Methanobacteriales), and the authentic acetogens affiliated to Firmicutes decreased after the intervention. Principal coordinates analysis (PCoA) and Jackknife environment clusters revealed evidence on the shift of the microbial community structure among the samples. Quantitative analysis of methanogens via qPCR showed that Methanobacteriales and Methanomicrobiales increased after nutrient addition, while acetoclastic methanogens (Methanosaetaceae) changed slightly. Nutrient treatment activated native CO 2 -reducing methanogens in oil reservoir. The high frequency of Methanobacteriales and Methanomicrobiales (CO 2 -reducers) after nutrient addition in this petroleum system suggested that CO 2 -reducing methanogenesis was involved in methane production. The nutrient addition could promote the methane production. The results will likely improve strategies of utilizing microorganisms in subsurface environments. Copyright © 2016 The Society for Biotechnology, Japan. Published by Elsevier B.V. All rights reserved.

  4. Succession in the petroleum reservoir microbiome through an oil field production lifecycle.

    Science.gov (United States)

    Vigneron, Adrien; Alsop, Eric B; Lomans, Bartholomeus P; Kyrpides, Nikos C; Head, Ian M; Tsesmetzis, Nicolas

    2017-09-01

    Subsurface petroleum reservoirs are an important component of the deep biosphere where indigenous microorganisms live under extreme conditions and in isolation from the Earth's surface for millions of years. However, unlike the bulk of the deep biosphere, the petroleum reservoir deep biosphere is subject to extreme anthropogenic perturbation, with the introduction of new electron acceptors, donors and exogenous microbes during oil exploration and production. Despite the fundamental and practical significance of this perturbation, there has never been a systematic evaluation of the ecological changes that occur over the production lifetime of an active offshore petroleum production system. Analysis of the entire Halfdan oil field in the North Sea (32 producing wells in production for 1-15 years) using quantitative PCR, multigenic sequencing, comparative metagenomic and genomic bins reconstruction revealed systematic shifts in microbial community composition and metabolic potential, as well as changing ecological strategies in response to anthropogenic perturbation of the oil field ecosystem, related to length of time in production. The microbial communities were initially dominated by slow growing anaerobes such as members of the Thermotogales and Clostridiales adapted to living on hydrocarbons and complex refractory organic matter. However, as seawater and nitrate injection (used for secondary oil production) delivered oxidants, the microbial community composition progressively changed to fast growing opportunists such as members of the Deferribacteres, Delta-, Epsilon- and Gammaproteobacteria, with energetically more favorable metabolism (for example, nitrate reduction, H 2 S, sulfide and sulfur oxidation). This perturbation has profound consequences for understanding the microbial ecology of the system and is of considerable practical importance as it promotes detrimental processes such as reservoir souring and metal corrosion. These findings provide a new

  5. Permeability studies of redox-sensitive nitroxyl spin probes in corn oil using an L-band ESR spectrometer

    Energy Technology Data Exchange (ETDEWEB)

    Jebaraj, D. David [Department of Physics, The American College, Madurai-625 002, Tamilnadu (India); Utsumi, Hideo [Innovation Center for Medical Redox Navigation, Kyushu University, Fukuoka 812-8582 (Japan); Asath, R. Mohamed; Benial, A. Milton Franklin, E-mail: miltonfranklin@yahoo.com [Department of Physics, NMSSVN College, Madurai-625 019, Tamilnadu (India)

    2016-05-23

    Electron spin resonance (ESR) studies were carried out for 2mM {sup 14}N labeled {sup 2}H enriched 3-methoxycarbonyl-2,2,5,5-tetramethyl-pyrrolidine-1-oxyl (MC-PROXYL) and 3–carboxy-2,2,5,5,-tetramethyl-1-pyrrolidinyloxy (carboxy-PROXYL) in pure water and various concentrations of corn oil. The ESR parameters, such as the line width, hyperfine coupling constant, g-factor, rotational correlation time, partition parameter and permeability were reported for the samples. The line width broadening was observed for both nitroxyl radicals in corn oil solutions. The partition parameter for permeable MC-PROXYL in corn oil increases with increasing concentration of corn oil, which reveals that the nitroxyl spin probe permeates into the oil phase. From the results, the corn oil concentration was optimized as 50 % for phantom studies. The rotational correlation time also increases with increasing concentration of corn oil. The permeable and impermeable nature of nitroxyl spin probes was demonstrated. These results will be useful for the development of ESR/OMR imaging modalities in in vivo and in vitro studies.

  6. Permeability studies of redox-sensitive nitroxyl spin probes in corn oil using an L-band ESR spectrometer

    International Nuclear Information System (INIS)

    Jebaraj, D. David; Utsumi, Hideo; Asath, R. Mohamed; Benial, A. Milton Franklin

    2016-01-01

    Electron spin resonance (ESR) studies were carried out for 2mM 14 N labeled 2 H enriched 3-methoxycarbonyl-2,2,5,5-tetramethyl-pyrrolidine-1-oxyl (MC-PROXYL) and 3–carboxy-2,2,5,5,-tetramethyl-1-pyrrolidinyloxy (carboxy-PROXYL) in pure water and various concentrations of corn oil. The ESR parameters, such as the line width, hyperfine coupling constant, g-factor, rotational correlation time, partition parameter and permeability were reported for the samples. The line width broadening was observed for both nitroxyl radicals in corn oil solutions. The partition parameter for permeable MC-PROXYL in corn oil increases with increasing concentration of corn oil, which reveals that the nitroxyl spin probe permeates into the oil phase. From the results, the corn oil concentration was optimized as 50 % for phantom studies. The rotational correlation time also increases with increasing concentration of corn oil. The permeable and impermeable nature of nitroxyl spin probes was demonstrated. These results will be useful for the development of ESR/OMR imaging modalities in in vivo and in vitro studies.

  7. Integrating gravimetric and interferometric synthetic aperture radar data for enhancing reservoir history matching of carbonate gas and volatile oil reservoirs

    KAUST Repository

    Katterbauer, Klemens; Arango, Santiago; Sun, Shuyu; Hoteit, Ibrahim

    2016-01-01

    Reservoir history matching is assuming a critical role in understanding reservoir characteristics, tracking water fronts, and forecasting production. While production data have been incorporated for matching reservoir production levels

  8. Ignition procedure for in situ burning in oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    1971-04-14

    An ignition procedure for an in situ burning process is described. Hydrogen peroxide is used, with a compound to decompose the hydrogen peroxide. The decomposition increases the temperature, and the generated oxygen ignites the oil. The following can be used to decompose the hydrogen peroxide: (1) catalytic compounds having a large surface area, manganese oxide, salts of 2-valent iron, fine platinum, and methals on inert materials; (2) oxidizing agents such as permanganate; and (3) reducing agents such as hydrazine, hydroxylamine and their derivatives. (14 claims)

  9. Time lapse seismic observations and effects of reservoir compressibility at Teal South oil field

    Science.gov (United States)

    Islam, Nayyer

    One of the original ocean-bottom time-lapse seismic studies was performed at the Teal South oil field in the Gulf of Mexico during the late 1990's. This work reexamines some aspects of previous work using modern analysis techniques to provide improved quantitative interpretations. Using three-dimensional volume visualization of legacy data and the two phases of post-production time-lapse data, I provide additional insight into the fluid migration pathways and the pressure communication between different reservoirs, separated by faults. This work supports a conclusion from previous studies that production from one reservoir caused regional pressure decline that in turn resulted in liberation of gas from multiple surrounding unproduced reservoirs. I also provide an explanation for unusual time-lapse changes in amplitude-versus-offset (AVO) data related to the compaction of the producing reservoir which, in turn, changed an isotropic medium to an anisotropic medium. In the first part of this work, I examine regional changes in seismic response due to the production of oil and gas from one reservoir. The previous studies primarily used two post-production ocean-bottom surveys (Phase I and Phase II), and not the legacy streamer data, due to the unavailability of legacy prestack data and very different acquisition parameters. In order to incorporate the legacy data in the present study, all three post-stack data sets were cross-equalized and examined using instantaneous amplitude and energy volumes. This approach appears quite effective and helps to suppress changes unrelated to production while emphasizing those large-amplitude changes that are related to production in this noisy (by current standards) suite of data. I examine the multiple data sets first by using the instantaneous amplitude and energy attributes, and then also examine specific apparent time-lapse changes through direct comparisons of seismic traces. In so doing, I identify time-delays that, when

  10. Simulation study to determine the feasibility of injecting hydrogen sulfide, carbon dioxide and nitrogen gas injection to improve gas and oil recovery oil-rim reservoir

    Science.gov (United States)

    Eid, Mohamed El Gohary

    This study is combining two important and complicated processes; Enhanced Oil Recovery, EOR, from the oil rim and Enhanced Gas Recovery, EGR from the gas cap using nonhydrocarbon injection gases. EOR is proven technology that is continuously evolving to meet increased demand and oil production and desire to augment oil reserves. On the other hand, the rapid growth of the industrial and urban development has generated an unprecedented power demand, particularly during summer months. The required gas supplies to meet this demand are being stretched. To free up gas supply, alternative injectants to hydrocarbon gas are being reviewed to support reservoir pressure and maximize oil and gas recovery in oil rim reservoirs. In this study, a multi layered heterogeneous gas reservoir with an oil rim was selected to identify the most optimized development plan for maximum oil and gas recovery. The integrated reservoir characterization model and the pertinent transformed reservoir simulation history matched model were quality assured and quality checked. The development scheme is identified, in which the pattern and completion of the wells are optimized to best adapt to the heterogeneity of the reservoir. Lateral and maximum block contact holes will be investigated. The non-hydrocarbon gases considered for this study are hydrogen sulphide, carbon dioxide and nitrogen, utilized to investigate miscible and immiscible EOR processes. In November 2010, re-vaporization study, was completed successfully, the first in the UAE, with an ultimate objective is to examine the gas and condensate production in gas reservoir using non hydrocarbon gases. Field development options and proces schemes as well as reservoir management and long term business plans including phases of implementation will be identified and assured. The development option that maximizes the ultimate recovery factor will be evaluated and selected. The study achieved satisfactory results in integrating gas and oil

  11. Feasibility of microbially improved oil recovery (MIOR) in Northern German oil reservoirs; Bakterien zur Erhoehung des Entoelungsgrades in norddeutschen Erdoellagerstaetten

    Energy Technology Data Exchange (ETDEWEB)

    Amro, M. [Inst. fuer Erdoel- und Erdgasforschung, Clausthal-Zellerfeld (Germany); Kessel, D. [Inst. fuer Erdoel- und Erdgasforschung, Clausthal-Zellerfeld (Germany)

    1996-05-01

    The scope of this study was to investigate the feasibility of microbially improved oil recovery (MIOR) in Northern German oil reservoirs. Suitable bacterial strains had to be identified. The mechanisms for oil mobilization and incremental recovery had to be investigated. To this end, two independent methods were employed, namely static autoclave tests and dynamic flood experiments. The static tests were carried out without reservoir rock matrix to preselect suitable bacterial strains with a minimum of experimental effort. The selected strains were then tested in dynamic flood experiments under reservoir conditions on Bentheimer sandstone cores to quantify the oil recovery. Key results of the study are: (1) Two bacterial strains were found having excellent metabolic activity with potential for oil recovery under Northern German reservoir conditions. (2) These bacteria can be injected into and transported in the pores of the sandstone. (3) The metabolic activity of these bacteria leads to substantial incremental oil recovery in repeated injection - shut in - production cycles. (4) Incremental oil recovery is attributed to wettability change and biomass production by the metabolites of the bacteria. (orig.) [Deutsch] Das Ziel dieser Arbeit ist die Untersuchung der Anwendbarkeit der mikrobiell verbesserten Erdoelgewinnung in norddeutschen Lagerstaetten. Zunaechst waren hierfuer einsetzbare Bakterienstaemme zu identifizieren. Diese waren dann auf ihr Entoelungsvermoegen zu ueberpruefen. Schliesslich sollten die Entoelungsmechanismen ermittelt werden. Die Vorauswahl potentiell geeigneter Bakterienstaemme erfolgte durch verschiedene mikrobiologische Forschungsinstitute. Zur Minimierung des experimentellen Aufwands wurden diese Staemme dann im Institut fuer Erdoel- und Erdgasforschung in statischen Autoklavenversuchen unter Lagerstaettenbedingungen, jedoch noch ohne Lagerstaettengestein, auf ihre Stoffwechselaktivitaet sowie Art und Eigenschaften ihrer Stoffwechselprodukte

  12. Using Thermodynamics to Predict the Outcomes of Nitrate-Based Oil Reservoir Souring Control Interventions

    Directory of Open Access Journals (Sweden)

    Jan Dolfing

    2017-12-01

    Full Text Available Souring is the undesirable production of hydrogen sulfide (H2S in oil reservoirs by sulfate-reducing bacteria (SRB. Souring is a common problem during secondary oil recovery via water flooding, especially when seawater with its high sulfate concentration is introduced. Nitrate injection into these oil reservoirs can prevent and remediate souring by stimulating nitrate-reducing bacteria (NRB. Two conceptually different mechanisms for NRB-facilitated souring control have been proposed: nitrate-sulfate competition for electron donors (oil-derived organics or H2 and nitrate driven sulfide oxidation. Thermodynamics can facilitate predictions about which nitrate-driven mechanism is most likely to occur in different scenarios. From a thermodynamic perspective the question “Which reaction yields more energy, nitrate driven oxidation of sulfide or nitrate driven oxidation of organic compounds?” can be rephrased as: “Is acetate driven sulfate reduction to sulfide exergonic or endergonic?” Our analysis indicates that under conditions encountered in oil fields, sulfate driven oxidation of acetate (or other SRB organic electron donors is always more favorable than sulfide oxidation to sulfate. That predicts that organotrophic NRB that oxidize acetate would outcompete lithotrophic NRB that oxidize sulfide. However, sulfide oxidation to elemental sulfur is different. At low acetate HS− oxidation is more favorable than acetate oxidation. Incomplete oxidation of sulfide to S0 is likely to occur when nitrate levels are low, and is favored by low temperatures; conditions that can be encountered at oil field above-ground facilities where intermediate sulfur compounds like S0 may cause corrosion. These findings have implications for reservoir management strategies and for assessing the success and progress of nitrate-based souring control strategies and the attendant risks of corrosion associated with souring and nitrate injection.

  13. Managing Injected Water Composition To Improve Oil Recovery: A Case Study of North Sea Chalk Reservoirs

    DEFF Research Database (Denmark)

    Zahid, Adeel; Shapiro, Alexander; Stenby, Erling Halfdan

    2012-01-01

    of the temperature dependence of the oil recovery indicated that the interaction of the ions contained in brine with the rock cannot be the only determining mechanism of enhanced recovery. We observed no substitution of Ca2+ ions with Mg2+ ions at high temperatures for both rocks. Not only the injection brine......In recent years, many core displacement experiments of oil by seawater performed on chalk rock samples have reported SO42–, Ca2+, and Mg2+ as potential determining ions for improving oil recovery. Most of these studies were carried out with outcrop chalk core plugs. The objective of this study...... is to investigate the potential of the advanced waterflooding process by carrying out experiments with reservoir chalk samples. The study results in a better understanding of the mechanisms involved in increasing the oil recovery with potential determining ions. We carried out waterflooding instead of spontaneous...

  14. Play-level distributions of estimates of recovery factors for a miscible carbon dioxide enhanced oil recovery method used in oil reservoirs in the conterminous United States

    Science.gov (United States)

    Attanasi, E.D.; Freeman, P.A.

    2016-03-02

    In a U.S. Geological Survey (USGS) study, recovery-factor estimates were calculated by using a publicly available reservoir simulator (CO2 Prophet) to estimate how much oil might be recovered with the application of a miscible carbon dioxide (CO2) enhanced oil recovery (EOR) method to technically screened oil reservoirs located in onshore and State offshore areas in the conterminous United States. A recovery factor represents the percentage of an oil reservoir’s original oil in place estimated to be recoverable by the application of a miscible CO2-EOR method. The USGS estimates were calculated for 2,018 clastic and 1,681 carbonate candidate reservoirs in the “Significant Oil and Gas Fields of the United States Database” prepared by Nehring Associates, Inc. (2012).

  15. APPLICATION OF INTEGRATED RESERVOIR MANAGEMENT AND RESERVOIR CHARACTERIZATION

    Energy Technology Data Exchange (ETDEWEB)

    Jack Bergeron; Tom Blasingame; Louis Doublet; Mohan Kelkar; George Freeman; Jeff Callard; David Moore; David Davies; Richard Vessell; Brian Pregger; Bill Dixon; Bryce Bezant

    2000-03-01

    Reservoir performance and characterization are vital parameters during the development phase of a project. Infill drilling of wells on a uniform spacing, without regard to characterization does not optimize development because it fails to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, especially carbonate reservoirs. These reservoirs are typically characterized by: (1) large, discontinuous pay intervals; (2) vertical and lateral changes in reservoir properties; (3) low reservoir energy; (4) high residual oil saturation; and (5) low recovery efficiency. The operational problems they encounter in these types of reservoirs include: (1) poor or inadequate completions and stimulations; (2) early water breakthrough; (3) poor reservoir sweep efficiency in contacting oil throughout the reservoir as well as in the nearby well regions; (4) channeling of injected fluids due to preferential fracturing caused by excessive injection rates; and (5) limited data availability and poor data quality. Infill drilling operations only need target areas of the reservoir which will be economically successful. If the most productive areas of a reservoir can be accurately identified by combining the results of geological, petrophysical, reservoir performance, and pressure transient analyses, then this ''integrated'' approach can be used to optimize reservoir performance during secondary and tertiary recovery operations without resorting to ''blanket'' infill drilling methods. New and emerging technologies such as geostatistical modeling, rock typing, and rigorous decline type curve analysis can be used to quantify reservoir quality and the degree of interwell communication. These results can then be used to develop a 3-D simulation model for prediction of infill locations. The application of reservoir surveillance techniques to identify additional reservoir ''pay'' zones

  16. Offset Risk Minimization for Open-loop Optimal Control of Oil Reservoirs

    DEFF Research Database (Denmark)

    Capolei, Andrea; Christiansen, Lasse Hjuler; Jørgensen, J. B.

    2017-01-01

    Simulation studies of oil field water flooding have demonstrated a significant potential of optimal control technology to improve industrial practices. However, real-life applications are challenged by unknown geological factors that make reservoir models highly uncertain. To minimize...... the associated financial risks, the oil literature has used ensemble-based methods to manipulate the net present value (NPV) distribution by optimizing sample estimated risk measures. In general, such methods successfully reduce overall risk. However, as this paper demonstrates, ensemble-based control strategies...... practices. The results suggest that it may be more relevant to consider the NPV offset distribution than the NPV distribution when minimizing risk in production optimization....

  17. Unstructured grids and an element based conservative approach for a black-oil reservoir simulation

    Energy Technology Data Exchange (ETDEWEB)

    Nogueira, Regis Lopes; Fernandes, Bruno Ramon Batista [Federal University of Ceara, Fortaleza, CE (Brazil). Dept. of Chemical Engineering; Araujo, Andre Luiz de Souza [Federal Institution of Education, Science and Technology of Ceara - IFCE, Fortaleza (Brazil). Industry Department], e-mail: andre@ifce.edu.br; Marcondes, Francisco [Federal University of Ceara, Fortaleza, CE (Brazil). Dept. of Metallurgical Engineering and Material Science], e-mail: marcondes@ufc.br

    2010-07-01

    Unstructured meshes presented one upgrade in modeling the main important features of the reservoir such as discrete fractures, faults, and irregular boundaries. From several methodologies available, the Element based Finite Volume Method (EbFVM), in conjunction with unstructured meshes, is one methodology that deserves large attention. In this approach, the reservoir, for 2D domains, is discretized using a mixed two-dimensional mesh using quadrilateral and triangle elements. After the initial step of discretization, each element is divided into sub-elements and the mass balance for each component is developed for each sub-element. The equations for each control-volume using a cell vertex construction are formulated through the contribution of different neighboured elements. This paper presents an investigation of an element-based approach using the black-oil model based on pressure and global mass fractions. In this approach, even when all gas phase is dissolved in oil phase the global mass fraction of gas will be different from zero. Therefore, no additional numerical procedure is necessary in order to treat the gas phase appear/disappearance. In this paper the above mentioned approach is applied to multiphase flows involving oil, gas, and water. The mass balance equations in terms of global mass fraction of oil, gas and water are discretized through the EbFVM and linearized by the Newton's method. The results are presented in terms of volumetric rates of oil, gas, and water and phase saturations. (author)

  18. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas - Near-term, Class I

    Energy Technology Data Exchange (ETDEWEB)

    Green, D.W.; Willhite, G.P.; Reynolds, Rodney R.; McCune, A. Dwayne; Michnick, Michael J.; Walton, Anthony W.; Watney, W. Lynn

    2000-06-08

    This project involved two demonstration projects, one in a Marrow reservoir located in the southwestern part of the state and the second in the Cherokee Group in eastern Kansas. Morrow reservoirs of western Kansas are still actively being explored and constitute an important resource in Kansas. Cumulative oil production from the Morrow in Kansas is over 400,000,000 bbls. Much of the production from the Morrow is still in the primary stage and has not reached the mature declining state of that in the Cherokee. The Cherokee Group has produced about 1 billion bbls of oil since the first commercial production began over a century ago. It is a billion-barrel plus resource that is distributed over a large number of fields and small production units. Many of the reservoirs are operated close to the economic limit, although the small units and low production per well are offset by low costs associated with the shallow nature of the reservoirs (less than 1000 ft. deep).

  19. Application of natural antimicrobial compounds for reservoir souring and MIC prevention in offshore oil and gas production systems

    DEFF Research Database (Denmark)

    Thomsen, Mette Hedegaard; Skovhus, Torben Lund; Mashietti, Marco

    Offshore oil production facilities are subjectable to internal corrosion, potentially leading to human and environmental risk and significant economic losses. Microbiologically influenced corrosion (MIC) and reservoir souring - sulphide production by sulfate reducing microorganisms in the reservo...

  20. Optimisation of Oil Production in Two – Phase Flow Reservoir Using Simultaneous Method and Interior Point Optimiser

    DEFF Research Database (Denmark)

    Lerch, Dariusz Michal; Völcker, Carsten; Capolei, Andrea

    2012-01-01

    in the reservoir. A promising decrease of these remained resources can be provided by smart wells applying water injections to sustain satisfactory pressure level in the reservoir throughout the whole process of oil production. Basically to enhance secondary recovery of the remaining oil after drilling, water...... is injected at the injection wells of the down-hole pipes. This sustains the pressure in the reservoir and drives oil towards production wells. There are however, many factors contributing to the poor conventional secondary recovery methods e.g. strong surface tension, heterogeneity of the porous rock...... fields, or closed loop optimisation, can be used for optimising the reservoir performance in terms of net present value of oil recovery or another economic objective. In order to solve an optimal control problem we use a direct collocation method where we translate a continuous problem into a discrete...

  1. Wettability of Oil-Producing Reservoir Rocks as Determined from X-ray Photoelectron Spectroscopy

    Science.gov (United States)

    Toledo; Araujo; Leon

    1996-11-10

    Wettability has a dominant effect in oil recovery by waterflooding and in many other processes of industrial and environmental interest. Recently, the suggestion has been made that surface science analytical techniques (SSAT) could be used to rapidly determine the wettability of reservoir materials. Here, we bring the capability of X-ray photoelectron spectroscopy (XPS) to bear on the wettability evaluation of producing reservoir rocks. For a suite of freshly exposed fracture surfaces of rocks we investigate the relationship between wettability and surface composition as determined from XPS. The classical wettability index as measured with the Amott-Harvey test is used here as an indicator of the wettability of natural sandstones. The XPS spectra of oil-wet surfaces of rocks reveal the existence of organic carbon and also of an "organic" silicon species, of the kind Si-CH relevant to silanes, having a well-defined binding energy which differs from that of the Si-O species of mineral grains. We provide quantifiable evidence that chemisorbed organic material on the pore surfaces defines the oil-wetting character of various reservoir sandstones studied here which on a mineralogic basis are expected to be water-wet. This view is supported by a strong correlation between C content of pore surfaces and rock wettability. The results also suggest a correlation between organic silicon content on the pore surfaces and rock hydrophobicity.

  2. Quantitative monitoring of gas flooding in oil-bearing reservoirs using a pulsed neutron tool

    International Nuclear Information System (INIS)

    Ruhovets, N.; Wyatt, D.F. Jr.

    1991-01-01

    This paper reports on quantitative monitoring of gas flooding in oil bearing reservoirs which is unique in that saturations of three fluids (gas, oil and water) in the effective pore space have to be determined, while in most other applications saturation behind casing is determined only for two fluids: hydrocarbons and water. A new method has been developed to monitor gas flooding of oil reservoirs. The method is based on computing two porosities: true effective (base) porosity determined before gas flooding, and apparent effective (monitor) porosity determined after gas flooding. The base porosity is determined from open and/or cased hole porosity logs run before the flooding. When open hole logs are available, the cased hole porosity logs are calibrated against open hole log. The monitor porosity is determined from one of the cased hole porosity logs, such as a neutron log or count rate ratio curve from a pulsed neutron log run after the gas flooding. The base and monitor porosities provide determination of the hydrogen index of the reservoir fluid after the flooding. This hydrogen index is then used to determine saturation of the flood agent after flooding. Water saturation after flooding can be determined from the equation which relates neutron total cross section (Σm) to volumetric constituent cross sections, using Σm values from a monitor run (after flooding)

  3. Mineral content prediction for unconventional oil and gas reservoirs based on logging data

    Science.gov (United States)

    Maojin, Tan; Youlong, Zou; Guoyue

    2012-09-01

    Coal bed methane and shale oil &gas are both important unconventional oil and gas resources, whose reservoirs are typical non-linear with complex and various mineral components, and the logging data interpretation model are difficult to establish for calculate the mineral contents, and the empirical formula cannot be constructed due to various mineral. The radial basis function (RBF) network analysis is a new method developed in recent years; the technique can generate smooth continuous function of several variables to approximate the unknown forward model. Firstly, the basic principles of the RBF is discussed including net construct and base function, and the network training is given in detail the adjacent clustering algorithm specific process. Multi-mineral content for coal bed methane and shale oil &gas, using the RBF interpolation method to achieve a number of well logging data to predict the mineral component contents; then, for coal-bed methane reservoir parameters prediction, the RBF method is used to realized some mineral contents calculation such as ash, volatile matter, carbon content, which achieves a mapping from various logging data to multimineral. To shale gas reservoirs, the RBF method can be used to predict the clay content, quartz content, feldspar content, carbonate content and pyrite content. Various tests in coalbed and gas shale show the method is effective and applicable for mineral component contents prediction

  4. Extended application of radon as a natural tracer in oil reservoirs

    Directory of Open Access Journals (Sweden)

    Moreira R.M.

    2013-05-01

    Full Text Available In the 80's it was a common practice in the study of contamination by NAPL to incorporate a tracer to the medium to be studied. At that time the first applications focused on the use of 222Rn, a naturally occurring radioactive isotope as a natural tracer, appropriate for thermodynamics studies, geology and transport properties in thermal reservoirs. In 1993 the deficit of radon was used to spot and quantify the contamination by DNAPL under the surface. For the first time these studies showed that radon could be used as a partitioning tracer. A methodology that provides alternatives to quantify the oil volume stored in the porous space of oil reservoirs is under development at CDTN. The methodology here applied, widens up and adapts the knowledge acquired from the use of radon as a tracer to the studies aimed at assessing SOR. It is a postulation of this work that once the radon partition coefficient between oil and water is known, SOR will be determined considering the increased amount of radon in the water phase as compared to the amount initially existent as the reservoir is flooded with water. This paper will present a description of the apparatus used and some preliminary results of the experiments.

  5. Experimental and numerical modeling of sulfur plugging in a carbonate oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Al-Awadhy, F. [ADMA-OPCO, Abudhabi (United Arab Emirates); Kocabas, I.; Abou-Kassem, J.H. [UAE University, Al Ain (United Arab Emirates); Islam, M.R. [Dalhousie University, Halifax, NS (United States)

    2005-01-15

    Many oil and gas reservoirs in the United Arab Emirates produce large amounts of sour gas, mainly in the form of hydrogen sulfide. In addition to creating problems in the production line, wellbore damage is often reported due to the precipitation of elemental sulfur in the vicinity of the wellbore. While there have been several studies performed on the role of solid deposition in a gas reservoir, the role of sulfur deposition in oil reservoirs has not been investigated. This article presents experimental results along with a comprehensive wellbore model that predicts sulfur precipitation as well as plugging. The experiments were conducted in a core (linear) system. Both analytical and numerical modelings were performed in a linear coordinate system. Data for the numerical model was obtained from both test tube and coreflood experiments. By using a phenomenological model, the wellbore plugging was modeled with an excellent match (with experimental results). The crude oil was de-asphalted prior to conducting the experiment in order to isolate the effect of asphaltene plugging. A series of coreflood tests was carried out to observe sulfur precipitation and plugging in a carbonate rock. Significant plugging was observed and was found to be dependent on flow rate and initial sulfur concentration. This information was used in the phenomenological model and can be incorporated in the wellbore numerical model. (author)

  6. A new flooding scheme by horizontal well in thin heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Liu, H.; Zhang, H.; Wang, M. [China Univ. of Petroleum, Beijing (China). MOE Key Laboratory of Petroleum Engineering ; Wang, Z. [Shengli Oil Field Co. (China). Dept. of Science and Technology]|[SINOPEC, Shengli (China)

    2008-10-15

    This paper presented a new flooding scheme for single horizontal wells that could improve recovery from thin marginal heavy oil reservoirs or from offshore reservoirs. The scheme involved the use of a multiple tubing string completion in a single wellbore. Special packers were installed within the long completion horizontal interval to establish an injection zone and a production zone. The new flooding scheme also involved simultaneous injection and production. Numerical simulation of the reservoir was used to determine the thickness of the formation and the lower limitation for different viscosities and the optimum time to start steam flooding after steam soaking by economic oil/steam ratio. The peak recovery efficiency of steam flooding was shown to occur when the length of separation section ratio is 0.15 to 0.2. It was concluded that high thermal efficiency in horizontal wells with long completion intervals can be maintained by alternating between steam soaking and steam flooding. Suitable alternation time to steam flooding is a seventh cycle for horizontal wells. Water cut and pressure difference will increase the steam injection rate, and thereby improve the oil production rate. The suitable injection rate for steam flooding is 2.4 t/d.ha.h because of its slow pressure change. 11 refs., 7 figs.

  7. Well test mathematical model for fractures network in tight oil reservoirs

    Science.gov (United States)

    Diwu, Pengxiang; Liu, Tongjing; Jiang, Baoyi; Wang, Rui; Yang, Peidie; Yang, Jiping; Wang, Zhaoming

    2018-02-01

    Well test, especially build-up test, has been applied widely in the development of tight oil reservoirs, since it is the only available low cost way to directly quantify flow ability and formation heterogeneity parameters. However, because of the fractures network near wellbore, generated from artificial fracturing linking up natural factures, traditional infinite and finite conductivity fracture models usually result in significantly deviation in field application. In this work, considering the random distribution of natural fractures, physical model of fractures network is proposed, and it shows a composite model feature in the large scale. Consequently, a nonhomogeneous composite mathematical model is established with threshold pressure gradient. To solve this model semi-analytically, we proposed a solution approach including Laplace transform and virtual argument Bessel function, and this method is verified by comparing with existing analytical solution. The matching data of typical type curves generated from semi-analytical solution indicates that the proposed physical and mathematical model can describe the type curves characteristic in typical tight oil reservoirs, which have up warping in late-term rather than parallel lines with slope 1/2 or 1/4. It means the composite model could be used into pressure interpretation of artificial fracturing wells in tight oil reservoir.

  8. Diffusion and spatially resolved NMR in Berea and Venezuelan oil reservoir rocks.

    Science.gov (United States)

    Murgich, J; Corti, M; Pavesi, L; Voltini, F

    1992-01-01

    Conventional and spatially resolved proton NMR and relaxation measurements are used in order to study the molecular motions and the equilibrium and nonequilibrium diffusion of oils in Berea sandstone and Venezuelan reservoir rocks. In the water-saturated Berea a single line with T*2 congruent to 150 microseconds is observed, while the relaxation recovery is multiexponential. In an oil reservoir rock (Ful 13) a single narrow line is present while a distribution of relaxation rates is evidenced from the recovery plots. On the contrary, in the Ful 7 sample (extracted at a deeper depth in a different zone) two NMR components are present, with 3.5 and 30 KHz linewidths, and the recovery plot exhibits biexponential law. No echo signal could be reconstructed in the oil reservoir rocks. These findings can be related to the effects in the micropores, where motions at very low frequency can occur in a thin layer. From a comparison of the diffusion constant in water-saturated Berea, D congruent to 5*10(-6) cm2/sec, with the ones in model systems, the average size of the pores is estimated around 40 A. The density profiles at the equilibrium show uniform distribution of oils or of water, and the relaxation rates appear independent from the selected slice. The nonequilibrium diffusion was studied as a function of time in a Berea cylinder with z axis along H0, starting from a thin layer of oil at the base, and detecting the spin density profiles d(z,t) with slice-selection techniques. Simultaneously, the values of T1's were measured locally, and the distribution of the relaxation rates was observed to be present in any slice.(ABSTRACT TRUNCATED AT 250 WORDS)

  9. Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

    Directory of Open Access Journals (Sweden)

    Si Le Van

    2016-09-01

    Full Text Available Heavy-oil resources represent a large percentage of global oil and gas reserves, however, owing to the high viscosity, enhanced oil recovery (EOR techniques are critical issues for extracting this type of crude oil from the reservoir. According to the survey data in Oil & Gas Journal, thermal methods are the most widely utilized in EOR projects in heavy oil fields in the US and Canada, and there are not many successful chemical flooding projects for heavy oil reported elsewhere in the world. However, thermal methods such as steam injection might be restricted in cases of thin formations, overlying permafrost, or reservoir depths over 4500 ft, for which chemical flooding becomes a better option for recovering crude oil. Moreover, owing to the considerable fluctuations in the oil price, chemical injection plans should be employed consistently in terms of either technical or economic viewpoints. The numerical studies in this work aim to clarify the predominant chemical injection schemes among the various combinations of chemical agents involving alkali (A, surfactant (S and polymer (P for specific heavy-oil reservoir conditions. The feasibilities of all potential injection sequences are evaluated in the pre-evaluation stage in order to select the most efficient injection scheme according to the variation in the oil price which is based on practical market values. Finally, optimization procedures in the post-evaluation stage are carried out for the most economic injection plan by an effective mathematic tool with the purpose of gaining highest Net Present Value (NPV of the project. In technical terms, the numerical studies confirm the predominant performances of sequences in which alkali-surfactant-polymer (ASP solution is injected after the first preflushing water whereby the recovery factor can be higher than 47%. In particular, the oil production performances are improved by injecting a buffering viscous fluid right after the first chemical slug

  10. Method of approximate electric modeling of oil reservoir operation with formation of a gas cap during mixed exploitation regime

    Energy Technology Data Exchange (ETDEWEB)

    Bragin, V A; Lyadkin, V Ya

    1969-01-01

    A potentiometric model is used to simulate the behavior of a reservoir in which pressure was dropped rapidly and solution gas migrated to the top of the structure forming a gas cap. Behavior of the system was represented by a differential equation, which was solved by an electrointegrator. The potentiometric model was found to closely represent past history of the reservoir, and to predict its future behavior. When this method is used in reservoirs where large pressure drops occur, repeated determination should be made at various time intervals, so that changes in relative permeability are taken into account.

  11. Well and Inflow Performance Relationship for Heavy Oil Reservoir under Heating Treatment

    KAUST Repository

    Hakiki, Farizal

    2017-10-17

    Well and Inflow Performance Relationship, termed TPR and IPR, respectively have been the unfailing methods to predict well performance. It is further to determine the schemes on optimising production. The main intention of the study is to explore TPR and IPR under heating treatment for heavy oil well. Klamono is a mature field which mostly has depleted wells, it produces heavy oil within 18.5 °API (>0.95 g/cc oil density), and therefore, artificial lifting method is necessary. Sucker Road Pump (SRP) and Electrical Submersible Pump (ESP) are the most deployed artificial lifting method in this reservoir. To boost the heavy oil production, the application of Electric Downhole Heater (EDH) in Well KLO-X1 is being studied. Whole Klamono\\'s production is more than 100,000 blpd within 97-99% water cut. By installing EDH, oil viscosity is decreased hence oil mobility ratio will play a role to decrease water cut. EDH is installed together with the tubing joint to simplify its application in the wellbore. The study shows that EDH application can elevate fluid (mixed oil and brine) temperature. Oil viscosity confirms a reduction from 68 to 46 cP. The gross well production is up to 12.2 bopd due optimising its outflow performance and reducing 97.5 to 96.9% water cut. The field data gives an incremental of 4.9 bopd. The computational results only show an attainment of net oil production up to 8.3 bopd (2 bopd incremental). The EDH works to lessen both density and viscosity as we hypothesised for the mechanism of thermally induced oil production improvement. The evaluation study on its economics aspect exhibits good result that is 1.4 USD/bbl additional profit margin according to field data despite the challenging annual rig rent cost. Following the field data, the expected net income through analytical model revealed that this project is financially promising.

  12. Well and Inflow Performance Relationship for Heavy Oil Reservoir under Heating Treatment

    KAUST Repository

    Hakiki, Farizal; Aditya, A.; Ulitha, D. T.; Shidqi, M.; Adi, W. S.; Wibowo, K. H.; Barus, M.

    2017-01-01

    Well and Inflow Performance Relationship, termed TPR and IPR, respectively have been the unfailing methods to predict well performance. It is further to determine the schemes on optimising production. The main intention of the study is to explore TPR and IPR under heating treatment for heavy oil well. Klamono is a mature field which mostly has depleted wells, it produces heavy oil within 18.5 °API (>0.95 g/cc oil density), and therefore, artificial lifting method is necessary. Sucker Road Pump (SRP) and Electrical Submersible Pump (ESP) are the most deployed artificial lifting method in this reservoir. To boost the heavy oil production, the application of Electric Downhole Heater (EDH) in Well KLO-X1 is being studied. Whole Klamono's production is more than 100,000 blpd within 97-99% water cut. By installing EDH, oil viscosity is decreased hence oil mobility ratio will play a role to decrease water cut. EDH is installed together with the tubing joint to simplify its application in the wellbore. The study shows that EDH application can elevate fluid (mixed oil and brine) temperature. Oil viscosity confirms a reduction from 68 to 46 cP. The gross well production is up to 12.2 bopd due optimising its outflow performance and reducing 97.5 to 96.9% water cut. The field data gives an incremental of 4.9 bopd. The computational results only show an attainment of net oil production up to 8.3 bopd (2 bopd incremental). The EDH works to lessen both density and viscosity as we hypothesised for the mechanism of thermally induced oil production improvement. The evaluation study on its economics aspect exhibits good result that is 1.4 USD/bbl additional profit margin according to field data despite the challenging annual rig rent cost. Following the field data, the expected net income through analytical model revealed that this project is financially promising.

  13. Feasibility study of the in-situ combustion in shallow, thin, and multi-layered heavy oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Zhong, L. [Society of Petroleum Engineers, Kuala Lumpur (Malaysia)]|[Daqing Petroleum Inst., Beijing (China); Yu, D. [Daqing Petroleum Inst., Beijing (China); Gong, Y. [China National Petroleum Corp., Beijing (China). Liaohe Oilfield; Wang, P.; Zhang, L. [China National Petroleum Corp., Beijing (China). Huabei Oilfield; Liu, C. [China National Petroleum Corp., Beijing (China). JiLin Oilfield

    2008-10-15

    In situ combustion is a process where oxygen is injected into oil reservoirs in order to oxidize the heavier components of crude oil. The oil is driven towards the production wells by the combustion gases and steam generated by the combustion processes. This paper investigated dry and wet forward in situ combustion processes designed for an oil reservoir with thin sand layers. Laboratory and numerical simulations were conducted to demonstrate the feasibility of the processes in a shallow, thin, heterogenous heavy oil reservoir in China. Combustion tube experiments were conducted in order to determine fuel consumption rates. A numerical geological model was constructed to represent the reservoir conditions. Gas, water, oil and solid phases were modelled. Four processes were considered: cracking; pyrolysis of heavy fractions; the combustion of light and heavy fractions; and the combustion of coke. Oil recovery rates were calculated for a period of 10 years. Reactor experiments were conducted to investigate igniting temperatures and air injection rates using an apparatus comprised of an electric heater, oil sand pack tube and a computerized control system. Experiments were performed at different temperature and injection rates. The experiments demonstrated that ignition times and air volumes decreased when air temperature was increased. Results of the study showed that a 20 per cent increase in oil recovery using the in situ combustion processes. It was concluded that adequate air injection rates are needed to ensure effective combustion front movement. 4 refs., 6 tabs., 4 figs.

  14. Characteristics of waterflooding of oil pools with clay-containing reservoir rocks

    Energy Technology Data Exchange (ETDEWEB)

    Zheltov, Yu V; Stupochenko, V E; Khavkin, A Ya; Martos, V N

    1981-01-01

    When planning the development of oil fields with reservoir pressure maintenance by the injection of water or activated solutions (surfactants, alkali, etc.), it is necessary to take into account the consequences of phenomena related to clay swelling. For this purpose, it is necessary to measure on a core the parameters characterizing the change and hysteresis of the filtration and storage properties of the reservoir rocks. Swelling of the clay component of the rock along with reducing these properties in the sweep zone can promote an increase of the efficiency of displacing oil by water. Theoretical investigations showed that the maximum displacement efficiency in homogeneous clay-containing rocks does not depend on the time of starting stimulation by demineralized waters. The efficiency from changing the mineralization of the stimulating agent increases with increase of viscosity of the oil. Under certain physical and geologic conditions, a purposeful change of the filtration and storage properties by increasing or decreasing clay swelling can increase the efficiency of developing the field and can increase oil recovery.

  15. 3-D Reservoir and Stochastic Fracture Network Modeling for Enhanced Oil Recovery, Circle Ridge Phosphoria/Tensleep Reservoir, and River Reservation, Arapaho and Shoshone Tribes, Wyoming

    Energy Technology Data Exchange (ETDEWEB)

    La Pointe, Paul R.; Hermanson, Jan

    2002-09-09

    The goal of this project is to improve the recovery of oil from the Circle Ridge Oilfield, located on the Wind River Reservation in Wyoming, through an innovative integration of matrix characterization, structural reconstruction, and the characterization of the fracturing in the reservoir through the use of discrete fracture network models.

  16. A lithology identification method for continental shale oil reservoir based on BP neural network

    Science.gov (United States)

    Han, Luo; Fuqiang, Lai; Zheng, Dong; Weixu, Xia

    2018-06-01

    The Dongying Depression and Jiyang Depression of the Bohai Bay Basin consist of continental sedimentary facies with a variable sedimentary environment and the shale layer system has a variety of lithologies and strong heterogeneity. It is difficult to accurately identify the lithologies with traditional lithology identification methods. The back propagation (BP) neural network was used to predict the lithology of continental shale oil reservoirs. Based on the rock slice identification, x-ray diffraction bulk rock mineral analysis, scanning electron microscope analysis, and the data of well logging and logging, the lithology was divided with carbonate, clay and felsic as end-member minerals. According to the core-electrical relationship, the frequency histogram was then used to calculate the logging response range of each lithology. The lithology-sensitive curves selected from 23 logging curves (GR, AC, CNL, DEN, etc) were chosen as the input variables. Finally, the BP neural network training model was established to predict the lithology. The lithology in the study area can be divided into four types: mudstone, lime mudstone, lime oil-mudstone, and lime argillaceous oil-shale. The logging responses of lithology were complicated and characterized by the low values of four indicators and medium values of two indicators. By comparing the number of hidden nodes and the number of training times, we found that the number of 15 hidden nodes and 1000 times of training yielded the best training results. The optimal neural network training model was established based on the above results. The lithology prediction results of BP neural network of well XX-1 showed that the accuracy rate was over 80%, indicating that the method was suitable for lithology identification of continental shale stratigraphy. The study provided the basis for the reservoir quality and oily evaluation of continental shale reservoirs and was of great significance to shale oil and gas exploration.

  17. Identification of carbonate reservoirs based on well logging data for boreholes drilled using oil base muds

    International Nuclear Information System (INIS)

    Abdukhalikov, Ya.N; Serebrennikov, V.S.

    1979-01-01

    Experiment on carbonate reservoir identification according to well logging data for boreholes drilled using oil base muds is described. Pulse neutron-neutron logging (PNNL) was widely used at the territory of Pripyat' hole to solve the task. To evaluate volumetric clayiness of carbonate rocks the dependence of gamma-logging, that is data of gamma-logging against clayey rocks built for every hollow, is used. Quantitative estimation of clayiness of dense and clayey carbonate rocks-non-reservoirs is carried out on the basis of the data of neutron-gamma and acoustic logging. Porosity coefficient and lithological characteristic of rocks are also determined according to the data of acoustic and neutron gamma-logging

  18. CO2 Huff-n-Puff Process in a Light Oil Shallow Shelf Carbonate Reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Boomer, R.J.; Cole, R.; Kovar, M.; Prieditis, J.; Vogt, J.; Wehner, S.

    1999-02-24

    The application cyclic CO2, often referred to as the CO2 Huff-n-Puff process, may find its niche in the maturing waterfloods of the Permian Basin. Coupling the CO2 Huff-n-Puff process to miscible flooding applications could provide the needed revenue to sufficiently mitigate near-term negative cash flow concerns in capital-intensive miscible projects. Texaco Exploration and Production Inc. and the US Department of Energy have teamed up in a attempt to develop the CO2 Huff-n-Puff process in the Grayburg and San Andres formations which are light oil, shallow shelf carbonate reservoirs that exist throughout the Permian Basin. This cost-shared effort is intended to demonstrate the viability of this underutilized technology in a specific class of domestic reservoir.

  19. Control of Microbial Sulfide Production with Biocides and Nitrate in Oil Reservoir Simulating Bioreactors.

    Directory of Open Access Journals (Sweden)

    Yuan eXue

    2015-12-01

    Full Text Available Oil reservoir souring by the microbial reduction of sulfate to sulfide is unwanted, because it enhances corrosion of metal infrastructure used for oil production and processing. Reservoir souring can be prevented or remediated by the injection of nitrate or biocides, although injection of biocides into reservoirs is not commonly done. Whether combined application of these agents may give synergistic reservoir souring control is unknown. In order to address this we have used up-flow sand-packed bioreactors injected with 2 mM sulfate and volatile fatty acids (VFA, 3 mM each of acetate, propionate and butyrate at a flow rate of 3 or 6 pore volumes per day. Pulsed injection of the biocides glutaraldehyde (Glut, benzalkonium chloride (BAC and cocodiamine was used to control souring. Souring control was determined as the recovery time (RT needed to re-establish an aqueous sulfide concentration of 0.8-1 mM (of the 1.7-2 mM before the pulse. Pulses were either for a long time (120 h at low concentration (long-low or for a short time (1 h at high concentration (short-high. The short-high strategy gave better souring control with Glut, whereas the long-low strategy was better with cocodiamine. Continuous injection of 2 mM nitrate alone was not effective, because 3 mM VFA can fully reduce both 2 mM nitrate to nitrite and N2 and, subsequently, 2 mM sulfate to sulfide. No synergy was observed for short-high pulsed biocides and continuously injected nitrate. However, use of continuous nitrate and long-low pulsed biocide gave synergistic souring control with BAC and Glut, as indicated by increased RTs in the presence, as compared to the absence of nitrate. Increased production of nitrite, which increases the effectiveness of souring control by biocides, is the most likely cause for this synergy.

  20. Solar-generated steam for oil recovery: Reservoir simulation, economic analysis, and life cycle assessment

    International Nuclear Information System (INIS)

    Sandler, Joel; Fowler, Garrett; Cheng, Kris; Kovscek, Anthony R.

    2014-01-01

    Highlights: • Integrated assessment of solar thermal enhanced oil recovery (TEOR). • Analyses of reservoir performance, economics, and life cycle factors. • High solar fraction scenarios show economic viability for TEOR. • Continuous variable-rate steam injection meets the benchmarks set by conventional steam flood. - Abstract: The viability of solar thermal steam generation for thermal enhanced oil recovery (TEOR) in heavy-oil sands was evaluated using San Joaquin Valley, CA data. The effectiveness of solar TEOR was quantified through reservoir simulation, economic analysis, and life-cycle assessment. Reservoir simulations with continuous but variable rate steam injection were compared with a base-case Tulare Sand steamflood project. For equivalent average injection rates, comparable breakthrough times and recovery factors of 65% of the original oil in place were predicted, in agreement with simulations in the literature. Daily cyclic fluctuations in steam injection rate do not greatly impact recovery. Oil production rates do, however, show seasonal variation. Economic viability was established using historical prices and injection/production volumes from the Kern River oil field. For comparison, this model assumes that present day steam generation technologies were implemented at TEOR startup in 1980. All natural gas cogeneration and 100% solar fraction scenarios had the largest and nearly equal net present values (NPV) of $12.54 B and $12.55 B, respectively. Solar fraction refers to the steam provided by solar steam generation. Given its large capital cost, the 100% solar case shows the greatest sensitivity to discount rate and no sensitivity to natural gas price. Because there are very little emissions associated with day-to-day operations from the solar thermal system, life-cycle emissions are significantly lower than conventional systems even when the embodied energy of the structure is considered. We estimate that less than 1 g of CO 2 /MJ of refined

  1. Cost Effective Surfactant Formulations for Improved Oil Recovery in Carbonate Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    William A. Goddard; Yongchun Tang; Patrick Shuler; Mario Blanco; Yongfu Wu

    2007-09-30

    This report summarizes work during the 30 month time period of this project. This was planned originally for 3-years duration, but due to its financial limitations, DOE halted funding after 2 years. The California Institute of Technology continued working on this project for an additional 6 months based on a no-cost extension granted by DOE. The objective of this project is to improve the performance of aqueous phase formulations that are designed to increase oil recovery from fractured, oil-wet carbonate reservoir rock. This process works by increasing the rate and extent of aqueous phase imbibition into the matrix blocks in the reservoir and thereby displacing crude oil normally not recovered in a conventional waterflood operation. The project had three major components: (1) developing methods for the rapid screening of surfactant formulations towards identifying candidates suitable for more detailed evaluation, (2) more fundamental studies to relate the chemical structure of acid components of an oil and surfactants in aqueous solution as relates to their tendency to wet a carbonate surface by oil or water, and (3) a more applied study where aqueous solutions of different commercial surfactants are examined for their ability to recover a West Texas crude oil from a limestone core via an imbibition process. The first item, regarding rapid screening methods for suitable surfactants has been summarized as a Topical Report. One promising surfactant screening protocol is based on the ability of a surfactant solution to remove aged crude oil that coats a clear calcite crystal (Iceland Spar). Good surfactant candidate solutions remove the most oil the quickest from the surface of these chips, plus change the apparent contact angle of the remaining oil droplets on the surface that thereby indicate increased water-wetting. The other fast surfactant screening method is based on the flotation behavior of powdered calcite in water. In this test protocol, first the calcite

  2. Revitalizing a mature oil play: Strategies for finding and producing unrecovered oil in frio fluvial-deltaic sandstone reservoirs at South Texas. Annual report, October 1994--October 1995

    Energy Technology Data Exchange (ETDEWEB)

    Holtz, M.; Knox, P.; McRae, L. [and others

    1996-02-01

    The Frio Fluvial-Deltaic Sandstone oil play of South Texas has produced nearly 1 billion barrels of oil, yet it still contains about 1.6 billion barrels of unrecovered mobile oil and nearly the same amount of residual oil resources. Interwell-scale geologic facise models of Frio Fluvial-deltaic reservoirs are being combined with engineering assessments and geophysical evaluations in order to determine the controls that these characteristics exert on the location and volume or unrecovered mobile and residual oil. Progress in the third year centered on technology transfer. An overview of project tasks is presented.

  3. Strontium isotopic signatures of oil-field waters: Applications for reservoir characterization

    Science.gov (United States)

    Barnaby, R.J.; Oetting, G.C.; Gao, G.

    2004-01-01

    The 87Sr/86Sr compositions of formation waters that were collected from 71 wells producing from a Pennsylvanian carbonate reservoir in New Mexico display a well-defined distribution, with radiogenic waters (up to 0.710129) at the updip western part of the reservoir, grading downdip to less radiogenic waters (as low as 0.708903 to the east. Salinity (2800-50,000 mg/L) displays a parallel trend; saline waters to the west pass downdip to brackish waters. Elemental and isotopic data indicate that the waters originated as meteoric precipitation and acquired their salinity and radiogenic 87Sr through dissolution of Upper Permian evaporites. These meteoric-derived waters descended, perhaps along deeply penetrating faults, driven by gravity and density, to depths of more than 7000 ft (2100 m). The 87 Sr/86Sr and salinity trends record influx of these waters along the western field margin and downdip flow across the field, consistent with the strong water drive, potentiometric gradient, and tilted gas-oil-water contacts. The formation water 87Sr/86Sr composition can be useful to evaluate subsurface flow and reservoir behavior, especially in immature fields with scarce pressure and production data. In mature reservoirs, Sr Sr isotopes can be used to differentiate original formation water from injected water for waterflood surveillance. Strontium isotopes thus provide a valuable tool for both static and dynamic reservoir characterization in conjunction with conventional studies using seismic, log, core, engineering, and production data. Copyright ??2004. The American Association of Petroleum Geologist. All rights reserved.

  4. Recent developments in seismic seabed oil reservoir monitoring applications using fibre-optic sensing networks

    International Nuclear Information System (INIS)

    De Freitas, J M

    2011-01-01

    This review looks at recent developments in seismic seabed oil reservoir monitoring techniques using fibre-optic sensing networks. After a brief introduction covering the background and scope of the review, the following section focuses on state-of-the-art fibre-optic hydrophones and accelerometers used for seismic applications. Related metrology aspects of the sensor such as measurement of sensitivity, noise and cross-axis performance are addressed. The third section focuses on interrogation systems. Two main phase-based competing systems have emerged over the past two decades for seismic applications, with a third technique showing much promise; these have been compared in terms of general performance. (topical review)

  5. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman R. Morrow

    2006-01-01

    The objectives of this project are: (1) to improve understanding of the wettability alteration of mixed-wet rocks that results from contact with the components of synthetic oil-based drilling and completion fluids formulated to meet the needs of arctic drilling; (2) to investigate cleaning methods to reverse the wettability alteration of mixed-wet cores caused by contact with these SBM components; and (3) to develop new approaches to restoration of wetting that will permit the use of cores drilled with SBM formulations for valid studies of reservoir properties.

  6. 3D seismic modeling in geothermal reservoirs with a distribution of steam patch sizes, permeabilities and saturations, including ductility of the rock frame

    Science.gov (United States)

    Carcione, José M.; Poletto, Flavio; Farina, Biancamaria; Bellezza, Cinzia

    2018-06-01

    Seismic propagation in the upper part of the crust, where geothermal reservoirs are located, shows generally strong velocity dispersion and attenuation due to varying permeability and saturation conditions and is affected by the brittleness and/or ductility of the rocks, including zones of partial melting. From the elastic-plastic aspect, the seismic properties (seismic velocity, quality factor and density) depend on effective pressure and temperature. We describe the related effects with a Burgers mechanical element for the shear modulus of the dry-rock frame. The Arrhenius equation combined to the octahedral stress criterion define the Burgers viscosity responsible of the brittle-ductile behaviour. The effects of permeability, partial saturation, varying porosity and mineral composition on the seismic properties is described by a generalization of the White mesoscopic-loss model to the case of a distribution of heterogeneities of those properties. White model involves the wave-induced fluid flow attenuation mechanism, by which seismic waves propagating through small-scale heterogeneities, induce pressure gradients between regions of dissimilar properties, where part of the energy of the fast P-wave is converted to slow P (Biot)-wave. We consider a range of variations of the radius and size of the patches and thin layers whose probability density function is defined by different distributions. The White models used here are that of spherical patches (for partial saturation) and thin layers (for permeability heterogeneities). The complex bulk modulus of the composite medium is obtained with the Voigt-Reuss-Hill average. Effective pressure effects are taken into account by using exponential functions. We then solve the 3D equation of motion in the space-time domain, by approximating the White complex bulk modulus with that of a set of Zener elements connected in series. The Burgers and generalized Zener models allows us to solve the equations with a direct grid

  7. New life in old reservoirs - the microbial conversion of oil to methane

    Science.gov (United States)

    Gründger, Friederike; Feisthauer, Stefan; Richnow, Hans Hermann; Siegert, Michael; Krüger, Martin

    2010-05-01

    Since almost 20 years it is known from stable isotope studies that large amounts of biogenic methane are formed in oil reservoirs. The investigation of this degradation process and of the underlying biogeochemical controls are of economical and social importance, since even under optimal conditions, not more than 30-40 % of the oil in a reservoir is actually recovered. The conversion of parts of this non-recoverable oil via an appropriate biotechnological treatment into easily recoverable methane would provide an extensive and ecologically sound energy resource. Laboratory mesocosm as well as high pressure autoclave experiments with samples from different geosystems showed high methane production rates after the addition of oils, single hydrocarbons or coals. The variation of parameters, like temperature, pressure or salinity, showed a broad tolerance to environmental conditions. The fingerprinting of the microbial enrichments with DGGE showed a large bacterial diversity while that of Archaea was limited to three to four dominant species. The Q-PCR results showed the presence of high numbers of Archaea and Bacteria. To analyse their function, we measured the abundances of genes indicative of metal reduction (16S rRNA gene for Geobacteraceae), sulphate reduction (sulphate reductase, dsr), and methanogenesis (methyl coenzyme M-reductase, mcrA). The methanogenic consortia will be further characterised to determine enzymatic pathways and the individual role of each partner. Degradation pathways for different compounds will be studied using 13C-labelled substrates and molecular techniques. Our stable isotope data from both, methane produced in our incubations with samples from various ecosystems and field studies, implies a common methanogenic biodegradation mechanism, resulting in consistent patterns of hydrocarbon alteration.

  8. Bones and oil reservoirs : bioengineers use oilpatch technology to study fluid flow in bones

    Energy Technology Data Exchange (ETDEWEB)

    Marsters, S.

    2003-06-01

    The fact that porosity and the presence of channels are qualities that are common to oil reservoirs and bones, led to the use of reservoir modelling technology in investigating bone disorders and to the discovery of dramatic changes in the structure and blood supply of osteoarthritic bones that lie under degenerating cartilage. CMG (Computer Modelling Group) Ltd., developers of reservoir simulation software claim that their software packages can help with the modelling of cellular responses to strains and deformations that occur as fluid flows through bone after a traumatic event such as a tear in the anterior cruciate ligament, a common sports-related injury. Researchers at the University of Calgary expect that by looking at the changes in blood and fluid flow within the bone, they can attain a better understanding of the chain of events that leads to osteoarthritis. Better understanding of the progression of the disease could eventually lead to more precise administration of drugs to deal with osteoarthritic pain, and even to the prevention of painful arthritic joints.

  9. Development Optimization and Uncertainty Analysis Methods for Oil and Gas Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Ettehadtavakkol, Amin, E-mail: amin.ettehadtavakkol@ttu.edu [Texas Tech University (United States); Jablonowski, Christopher [Shell Exploration and Production Company (United States); Lake, Larry [University of Texas at Austin (United States)

    2017-04-15

    Uncertainty complicates the development optimization of oil and gas exploration and production projects, but methods have been devised to analyze uncertainty and its impact on optimal decision-making. This paper compares two methods for development optimization and uncertainty analysis: Monte Carlo (MC) simulation and stochastic programming. Two example problems for a gas field development and an oilfield development are solved and discussed to elaborate the advantages and disadvantages of each method. Development optimization involves decisions regarding the configuration of initial capital investment and subsequent operational decisions. Uncertainty analysis involves the quantification of the impact of uncertain parameters on the optimum design concept. The gas field development problem is designed to highlight the differences in the implementation of the two methods and to show that both methods yield the exact same optimum design. The results show that both MC optimization and stochastic programming provide unique benefits, and that the choice of method depends on the goal of the analysis. While the MC method generates more useful information, along with the optimum design configuration, the stochastic programming method is more computationally efficient in determining the optimal solution. Reservoirs comprise multiple compartments and layers with multiphase flow of oil, water, and gas. We present a workflow for development optimization under uncertainty for these reservoirs, and solve an example on the design optimization of a multicompartment, multilayer oilfield development.

  10. Development Optimization and Uncertainty Analysis Methods for Oil and Gas Reservoirs

    International Nuclear Information System (INIS)

    Ettehadtavakkol, Amin; Jablonowski, Christopher; Lake, Larry

    2017-01-01

    Uncertainty complicates the development optimization of oil and gas exploration and production projects, but methods have been devised to analyze uncertainty and its impact on optimal decision-making. This paper compares two methods for development optimization and uncertainty analysis: Monte Carlo (MC) simulation and stochastic programming. Two example problems for a gas field development and an oilfield development are solved and discussed to elaborate the advantages and disadvantages of each method. Development optimization involves decisions regarding the configuration of initial capital investment and subsequent operational decisions. Uncertainty analysis involves the quantification of the impact of uncertain parameters on the optimum design concept. The gas field development problem is designed to highlight the differences in the implementation of the two methods and to show that both methods yield the exact same optimum design. The results show that both MC optimization and stochastic programming provide unique benefits, and that the choice of method depends on the goal of the analysis. While the MC method generates more useful information, along with the optimum design configuration, the stochastic programming method is more computationally efficient in determining the optimal solution. Reservoirs comprise multiple compartments and layers with multiphase flow of oil, water, and gas. We present a workflow for development optimization under uncertainty for these reservoirs, and solve an example on the design optimization of a multicompartment, multilayer oilfield development.

  11. Distance determination of NPP and oil reservoir on enhanced oil recovery based on heat loss and safety in view point

    International Nuclear Information System (INIS)

    Erlan Dewita; Dedy Priambodo; Sudi Ariyanto

    2013-01-01

    EOR is a method used to increasing oil recovery by injecting material or other to the reservoir. There are 3 EOR technique have been used in the world, namely thermal injection, chemical injection dan Miscible. Thermal injection method is the method most widely used in the world, however, one drawback is the loss of heat during steam distribution to the injection wells. In Indonesia, EOR application has been successfully done in the field of Duri, Chevron uses steam injection method, but still use petroleum as a fuel for steam production. In order to save oil reserves, it was done the introduction of co-generation nuclear power plants to supply some of the heat of nuclear power plants for EOR processes. In cogeneration nuclear power plant, the safety aspect is main priority. The purpose of the study was to evaluate the distance NPP with oil wells by considering heat loss and safety aspects. The method of study and calculations done using Tempo Cycle program. The study results showed that in the distance of 400 meter as exclusion zone of PBMR reactor, with pipe insulation thickness 1 in, the amount of heat loss of 277, 883 kw, while in pipe isolation thickness 2 in, amount of heat loss became 162,634 kw and with isolation thickness 3 in, amount of heat loss 120,767 kw., heat loss can be overcome and provide insulation pipes and improve the quality of saturated steam into superheated. (author)

  12. Well Test Analysis of Naturally Fractured Vuggy Reservoirs with an Analytical Triple Porosity – Double Permeability Model and a Global Optimization Method

    Directory of Open Access Journals (Sweden)

    Gómez Susana

    2014-07-01

    Full Text Available The aim of this work is to study the automatic characterization of Naturally Fractured Vuggy Reservoirs via well test analysis, using a triple porosity-dual permeability model. The inter-porosity flow parameters, the storativity ratios, as well as the permeability ratio, the wellbore storage effect, the skin and the total permeability will be identified as parameters of the model. In this work, we will perform the well test interpretation in Laplace space, using numerical algorithms to transfer the discrete real data given in fully dimensional time to Laplace space. The well test interpretation problem in Laplace space has been posed as a nonlinear least squares optimization problem with box constraints and a linear inequality constraint, which is usually solved using local Newton type methods with a trust region. However, local methods as the one used in our work called TRON or the well-known Levenberg-Marquardt method, are often not able to find an optimal solution with a good fit of the data. Also well test analysis with the triple porosity-double permeability model, like most inverse problems, can yield multiple solutions with good match to the data. To deal with these specific characteristics, we will use a global optimization algorithm called the Tunneling Method (TM. In the design of the algorithm, we take into account issues of the problem like the fact that the parameter estimation has to be done with high precision, the presence of noise in the measurements and the need to solve the problem computationally fast. We demonstrate that the use of the TM in this study, showed to be an efficient and robust alternative to solve the well test characterization, as several optimal solutions, with very good match to the data were obtained.

  13. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM

    Energy Technology Data Exchange (ETDEWEB)

    Murphy, Mark B.

    1999-02-24

    The Nash Draw Brushy Canyon Pool in Eddy County New Mexico is a cost-shared field demonstration project in the US Department of Energy Class II Program. A major goal of the Class III Program is to stimulate the use of advanced technologies to increase ultimate recovery from slope-basin clastic reservoirs. Advanced characterization techniques are being used at the Nash Draw project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. Analysis, interpretation, and integration of recently acquired geologic, geophysical, and engineering data revealed that the initial reservoir characterization was too simplistic to capture the critical features of this complex formation. Contrary to the initial characterization, a new reservoir description evolved that provided sufficient detail regarding the complexity of the Brushy Canyon interval at Nash Draw. This new reservoir description is being used as a risk reduction tool to identify ''sweet spots'' for a development drilling program as well as to evaluate pressure maintenance strategies. The reservoir characterization, geological modeling, 3-D seismic interpretation, and simulation studies have provided a detailed model of the Brushy Canyon zones. This model was used to predict the success of different reservoir management scenarios and to aid in determining the most favorable combination of targeted drilling, pressure maintenance, well simulation, and well spacing to improve recovery from this reservoir.

  14. Geologic CO2 Sequestration: Predicting and Confirming Performance in Oil Reservoirs and Saline Aquifers

    Science.gov (United States)

    Johnson, J. W.; Nitao, J. J.; Newmark, R. L.; Kirkendall, B. A.; Nimz, G. J.; Knauss, K. G.; Ziagos, J. P.

    2002-05-01

    Reducing anthropogenic CO2 emissions ranks high among the grand scientific challenges of this century. In the near-term, significant reductions can only be achieved through innovative sequestration strategies that prevent atmospheric release of large-scale CO2 waste streams. Among such strategies, injection into confined geologic formations represents arguably the most promising alternative; and among potential geologic storage sites, oil reservoirs and saline aquifers represent the most attractive targets. Oil reservoirs offer a unique "win-win" approach because CO2 flooding is an effective technique of enhanced oil recovery (EOR), while saline aquifers offer immense storage capacity and widespread distribution. Although CO2-flood EOR has been widely used in the Permian Basin and elsewhere since the 1980s, the oil industry has just recently become concerned with the significant fraction of injected CO2 that eludes recycling and is therefore sequestered. This "lost" CO2 now has potential economic value in the growing emissions credit market; hence, the industry's emerging interest in recasting CO2 floods as co-optimized EOR/sequestration projects. The world's first saline aquifer storage project was also catalyzed in part by economics: Norway's newly imposed atmospheric emissions tax, which spurred development of Statoil's unique North Sea Sleipner facility in 1996. Successful implementation of geologic sequestration projects hinges on development of advanced predictive models and a diverse set of remote sensing, in situ sampling, and experimental techniques. The models are needed to design and forecast long-term sequestration performance; the monitoring techniques are required to confirm and refine model predictions and to ensure compliance with environmental regulations. We have developed a unique reactive transport modeling capability for predicting sequestration performance in saline aquifers, and used it to simulate CO2 injection at Sleipner; we are now

  15. Hydrogeology and geochemistry of low-permeability oil-shales - Case study from HaShfela sub-basin, Israel

    Science.gov (United States)

    Burg, Avihu; Gersman, Ronen

    2016-09-01

    Low permeability rocks are of great importance given their potential role in protecting underlying aquifers from surface and buried contaminants. Nevertheless, only limited data for these rocks is available. New appraisal wells drilled into the oil shale unit (OSU) of the Mt. Scopus Group in the HaShfela sub-basin, Central Israel, provided a one-time opportunity for detailed study of the hydrogeology and geochemistry of this very low permeability unit. Methods used include: slug tests, electrical logs, televiewer imaging, porosity and permeability measurements on core samples, chemical analyses of the rock column and groundwater analyses. Slug tests yielded primary indication to the low permeability of the OSU despite its high porosity (30-40%). Hydraulic conductivities as low as 10-10-10-12 m/s were calculated, using both the Hvorslev and Cooper-Bredehoeft-Papadopulos decoding methods. These low conductivities were confirmed by direct measurements of permeability in cores, and from calculations based on the Kozeny-Carman approach. Storativity was found to be 1 · 10-6 and specific storage - 3.8 · 10-9 m-1. Nevertheless, the very limited water flow in the OSU is argued to be driven gravitationally. The extremely slow recovery rates as well as the independent recovery of two adjacent wells, despite their initial large head difference of 214 m, indicate that the natural fractures are tight and are impermeable due to the confining stress at depth. Laboratory measured permeability is similar or even higher than the field-measured values, thereby confirming that fractures and bedding planes do not form continuous flow paths. The vertical permeability along the OSU is highly variable, implying hydraulic stratification and extremely low vertical hydraulic conductivity. The high salinity of the groundwater (6300-8000 mgCl/L) within the OSU and its chemical and isotopic compositions are explained by the limited water flow, suggesting long residence time of the water

  16. Isotopic and geochemical tools to assess the feasibility of methanogenesis as a way to enhance hydrocarbon recovery in oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Jimenez, N.; Morris, B.E.L.; Richnow, H.H. [Helmholtz-Zentrum fuer Umweltforschung (UFZ), Leipzig (Germany). Abt. Isotopenbiogeochemie; Cai, M.; Yao, Jun [Helmholtz-Zentrum fuer Umweltforschung (UFZ), Leipzig (Germany). Abt. Isotopenbiogeochemie; University of Sicence and Technology, Beijing (China). School of Civil and Environment Engineering; Straaten, N.; Krueger, M. [Bundesanstalt fuer Geowissenschaften und Rohstoffe (BGR), Hannover (Germany). Fachbereich Geochemie

    2013-08-01

    In situ biotransformation of oil to methane was investigated in a thermophilic reservoir in Dagang, China using isotopic analyzes, chemical fingerprinting and molecular and biological methods. Our first results, which were already published, demonstrated that anaerobic oil degradation concomitant with methane production was occurring. The reservoir was highly methanogenic and the oil exhibited varying degrees of degradation between different parts of the reservoir, although it was mainly highly weathered, and nearly devoid of nalkanes, alkylbenzenes, alkyltoluenes, and light PAHs. In addition, the isotopic data from reservoir oil, water and gas was used to elucidate the origin of the methane. The average {delta}{sup 13}C for methane was around -47 permille and CO{sub 2} was highly enriched in {sup 13}C. The bulk isotopic discrimination ({Delta}{delta}{sup 13}C) between methane and CO{sub 2} was between 32 and 65 permille, in accordance with previously reported results for methane formation during hydrocarbon degradation. Subsequent microcosm experiments revealed that autochthonous microbiota are capable of degrading oil under methanogenic conditions and of producing methane and/or CO{sub 2} from {sup 13}C-labelled n-hexadecane, 2-methylnaphthalene or toluene ({delta}{sup 13}C values up to 550 permille). These results demonstrate that methanogenesis is linked to aliphatic and aromatic hydrocarbon degradation. Further experiments will elucidate the activation mechanisms for the different compounds. (orig.)

  17. Neuro-Simulation Tool for Enhanced Oil Recovery Screening and Reservoir Performance Prediction

    Directory of Open Access Journals (Sweden)

    Soheil Bahrekazemi

    2017-09-01

    Full Text Available Assessment of the suitable enhanced oil recovery method in an oilfield is one of the decisions which are made prior to the natural drive production mechanism. In some cases, having in-depth knowledge about reservoir’s rock, fluid properties, and equipment is needed as well as economic evaluation. Both putting such data into simulation and its related consequent processes are generally very time consuming and costly.  In order to reduce study cases, an appropriate tool is required for primary screening prior to any operations being performed, to which leads reduction of time in design of ether pilot section or production under field condition. In this research, two different and useful screening tools are presented through a graphical user interface. The output of just over 900 simulations and verified screening criteria tables were employed to design the mentioned tools. Moreover, by means of gathered data and development of artificial neural networks, two dissimilar screening tools for proper assessment of suitable enhanced oil recovery method were finally introduced. The first tool is about the screening of enhanced oil recovery process based on published tables/charts and the second one which is Neuro-Simulation tool, concerns economical evaluation of miscible and immiscible injection of carbon dioxide, nitrogen and natural gas into the reservoir. Both of designed tools are provided in the form of a graphical user interface by which the user, can perceive suitable method through plot of oil recovery graph during 20 years of production, costs of gas injection per produced barrel, cumulative oil production, and finally, design the most efficient scenario.

  18. Heavy-oil recovery in naturally fractured reservoirs with varying wettability by steam solvent co-injection

    Energy Technology Data Exchange (ETDEWEB)

    Al Bahlani, A. [Alberta Univ., Edmonton, AB (Canada); Babadagli, T. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[Alberta Univ., Edmonton, AB (Canada)

    2008-10-15

    Steam injection may not be an efficient oil recovery process in certain circumstances, such as in deep reservoirs, where steam injection may be ineffective because of hot-water flooding due to excessive heat loss. Steam injection may also be ineffective in oil-wet fractured carbonates, where steam channels through fracture zones without effectively sweeping the matrix oil. Steam flooding is one of the many solutions for heavy oil recovery in unconsolidated sandstones that is in commercial production. However, heavy-oil fractured carbonates are more challenging, where the recovery is generally limited only to matrix oil drainage gravity due to unfavorable wettability or thermal expansion if heat is introduced during the process. This paper proposed a new approach to improve steam/hot-water injection and efficiency for heavy-oil fractured carbonate reservoirs. The paper provided background information on oil recovery from fractured carbonates and provided a statement of the problem. Three phases were described, including steam/hot-waterflooding phase (spontaneous imbibition); miscible flooding phase (diffusion); and steam/hot-waterflooding phase (spontaneous imbibition or solvent retention). The paper also discussed core preparation and saturation procedures. It was concluded that efficient oil recovery is possible using alternate injection of steam/hot water and solvent. 43 refs., 1 tab., 13 figs.

  19. Modelling and simulation of compressible fluid flow in oil reservoir: a case study of the Jubilee Field, Tano Basin (Ghana)

    International Nuclear Information System (INIS)

    Gawusu, S.

    2015-07-01

    Oil extraction represents an important investment and the control of a rational exploitation of a field means mastering various scientific techniques including the understanding of the dynamics of fluids in place. This thesis presents a theoretical investigation of the dynamic behaviour of an oil reservoir during its exploitation. The study investigated the dynamics of fluid flow patterns in a homogeneous oil reservoir using the Radial Diffusivity Equation (RDE) as well as two phase oil-water flow equations. The RDE model was solved analytically and numerically for pressure using the Constant Terminal Rate Solution (CTRS) and the fully implicit Finite Difference Method (FDM) respectively. The mathematical derivations of the models and their solution procedures were presented to allow for easy utilization of the techniques for reservoir and engineering applications. The study predicted that the initial oil reservoir pressure will be able to do the extraction for a very long time before any other recovery method will be used to aid in the extraction process depending on the rate of production. Reservoir simulation describing a one dimensional radial flow of a compressible fluid in porous media may be adequately performed using ordinary laptop computers as revealed by the study. For the simulation of MATLAB, the case of the Jubilee Fields, Tano Basin was studied, an algorithm was developed for the simulation of pressure in the reservoir. It ensues from the analysis of the plots of pressure vrs time and space that the Pressure Transient Analysis (PTA) was duly followed. The approximate solutions of the analytical and numerical solutions to the Radial Diffusivity Equation (RDE) were in excellent agreement, thus the reservoir simulation model developed can be used to describe typical pressure-time relationships that are used in conventional Pressure Transient Analysis (PTA). The study was extended to two phase oil-water flow in reservoirs. The flow of fluids in multi

  20. Game-Theory Based Research on Oil-Spill Prevention and Control Modes in Three Gorges Reservoir Area

    Science.gov (United States)

    Yin, Jie; Xiong, Ting

    2018-01-01

    Aiming at solving the existing oil pollution in the Three Gorges reservoir, this paper makes research on oil-spill prevention and control mode based on game theory. Regarding the built modes and comparative indicator system, overall efficiency indicator functions are used to compare general effect, overall cost, and overall efficiency, which concludes that the mode combining government and enterprise has the highest overall efficiency in preventing and controlling ship oil spills. The suggested mode together its correspondingly designed management system, has been applied to practice for a year in Three Gorges Reservoir Area and has made evident improvements to the existing oil pollution, meanwhile proved to be quite helpful to the pollution prevention and control in the lower reaches of Yangtze River.

  1. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Science.gov (United States)

    2010-07-01

    ... 30 Mineral Resources 2 2010-07-01 2010-07-01 false How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? (a...

  2. Influence of clay and silica on permeability and capillary entry pressure of chalk reservoirs in the North Sea

    DEFF Research Database (Denmark)

    Røgen, Birte; Fabricius, Ida Lykke

    2002-01-01

    specific surface area. Fifty-nine Tor and Ekofisk Formation chalk samples from five North Sea chalk reservoirs were investigated. All contain quartz and clay minerals, most commonly kaolinite and smectite, with trace amounts of illite. The contents of calcite and quartz are inversely correlated and both......)): calcite between 0.5 and 3.5, quartz about 5, kaolinite about 15, and smectite about 60....

  3. Effects of nitrate injection on microbial enhanced oil recovery and oilfield reservoir souring.

    Science.gov (United States)

    da Silva, Marcio Luis Busi; Soares, Hugo Moreira; Furigo, Agenor; Schmidell, Willibaldo; Corseuil, Henry Xavier

    2014-11-01

    Column experiments were utilized to investigate the effects of nitrate injection on sulfate-reducing bacteria (SRB) inhibition and microbial enhanced oil recovery (MEOR). An indigenous microbial consortium collected from the produced water of a Brazilian offshore field was used as inoculum. The presence of 150 mg/L volatile fatty acids (VFA´s) in the injection water contributed to a high biological electron acceptors demand and the establishment of anaerobic sulfate-reducing conditions. Continuous injection of nitrate (up to 25 mg/L) for 90 days did not inhibit souring. Contrariwise, in nitrogen-limiting conditions, the addition of nitrate stimulated the proliferation of δ-Proteobacteria (including SRB) and the associated sulfide concentration. Denitrification-specific nirK or nirS genes were not detected. A sharp decrease in water interfacial tension (from 20.8 to 14.5 mN/m) observed concomitantly with nitrate consumption and increased oil recovery (4.3 % v/v) demonstrated the benefits of nitrate injection on MEOR. Overall, the results support the notion that the addition of nitrate, at this particular oil reservoir, can benefit MEOR by stimulating the proliferation of fortuitous biosurfactant-producing bacteria. Higher nitrate concentrations exceeding the stoichiometric volatile fatty acid (VFA) biodegradation demands and/or the use of alternative biogenic souring control strategies may be necessary to warrant effective SRB inhibition down gradient from the injection wells.

  4. Microbial redox processes in deep subsurface environments and the potential application of (perchlorate in oil reservoirs

    Directory of Open Access Journals (Sweden)

    Martin G Liebensteiner

    2014-09-01

    Full Text Available The ability of microorganisms to thrive under oxygen-free conditions in subsurface environments relies on the enzymatic reduction of oxidized elements, such as sulfate, ferric iron or CO2, coupled to the oxidation of inorganic or organic compounds. A broad phylogenetic and functional diversity of microorganisms from subsurface environments has been described using isolation-based and advanced molecular ecological techniques. The physiological groups reviewed here comprise iron-, manganese- and nitrate-reducing microorganisms. In the context of recent findings also the potential of chlorate and perchlorate [jointly termed (perchlorate] reduction in oil reservoirs will be discussed. Special attention is given to elevated temperatures that are predominant in the deep subsurface. Microbial reduction of (perchlorate is a thermodynamically favorable redox process, also at high temperature. However, knowledge about (perchlorate reduction at elevated temperatures is still scarce and restricted to members of the Firmicutes and the archaeon Archaeoglobus fulgidus. By analyzing the diversity and phylogenetic distribution of functional genes in (metagenome databases and combining this knowledge with extrapolations to earlier-made physiological observations we speculate on the potential of (perchlorate reduction in the subsurface and more precisely oil fields. In addition, the application of (perchlorate for bioremediation, souring control and microbial enhanced oil recovery are addressed.

  5. OIL RESERVOIR CHARACTERIZATION AND CO2 INJECTION MONITORING IN THE PERMIAN BASIN WITH CROSSWELL ELECTROMAGNETIC IMAGING

    Energy Technology Data Exchange (ETDEWEB)

    Michael Wilt

    2004-02-01

    Substantial petroleum reserves exist in US oil fields that cannot be produced economically, at current prices, unless improvements in technology are forthcoming. Recovery of these reserves is vital to US economic and security interests as it lessens our dependence on foreign sources and keeps our domestic petroleum industry vital. Several new technologies have emerged that may improve the situation. The first is a series of new flooding techniques to re-pressurize reservoirs and improve the recovery. Of these the most promising is miscible CO{sub 2} flooding, which has been used in several US petroleum basins. The second is the emergence of new monitoring technologies to track and help manage this injection. One of the major players in here is crosswell electromagnetics, which has a proven sensitivity to reservoir fluids. In this project, we are applying the crosswell EM technology to a CO{sub 2} flood in the Permian Basin oil fields of New Mexico. With our partner ChevronTexaco, we are testing the suitability of using EM for tracking the flow of injected CO{sub 2} through the San Andreas reservoir in the Vacuum field in New Mexico. The project consisted of three phases, the first of which was a preliminary field test at Vacuum, where a prototype system was tested in oil field conditions including widely spaced wells with steel casing. The results, although useful, demonstrated that the older technology was not suitable for practical deployment. In the second phase of the project, we developed a much more powerful and robust field system capable of collecting and interpreting field data through steel-cased wells. The final phase of the project involved applying this system in field tests in the US and overseas. Results for tests in steam and water floods showed remarkable capability to image between steel wells and provided images that helped understand the geology and ongoing flood and helped better manage the field. The future of this technology is indeed bright

  6. Fundamentals of Reservoir Surface Energy as Related to Surface Properties, Wettability, Capillary Action, and Oil Recovery from Fractured Reservoirs by Spontaneous Imbibition

    Energy Technology Data Exchange (ETDEWEB)

    Norman Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Zhengxin Tong; Evren Unsal; Siluni Wickramathilaka; Shaochang Wo; Peigui Yin

    2008-06-30

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the non-wetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  7. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    Energy Technology Data Exchange (ETDEWEB)

    Norman R. Morrow

    2004-05-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  8. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    Energy Technology Data Exchange (ETDEWEB)

    Norman R. Morrow

    2004-07-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  9. A new method for the experimental determination of three-phase relative permeabilities

    International Nuclear Information System (INIS)

    Perez Carrillo, Edgar Ricardo; Jose Francisco Zapata Arango; Santos Santos, Nicolas

    2008-01-01

    Petroleum reservoirs under primary, secondary or tertiary recovery processes usually experience simultaneous flow of three fluids phases (oil, water and gas). Reports on some mathematical models for calculating three-phase relative permeability are available in the Literature. Nevertheless, many of these models were designed based on certain experimental conditions and reservoir rocks and fluids. Therefore, special care has to be taken when applying them to specific reservoirs. At the laboratory level, three-phase relative permeability can be calculated using experimental unsteady-state or steady state methodologies. This paper proposes an unsteady-state methodology to evaluate three-phase relative permeability using the equipment available at the petrophysical analysis Laboratory of the Instituto Colombiano del Petroleo (ICP) of Ecopetrol S.A. Improvements to the equipment were effected in order to achieve accuracy in the unsteady-state measurement of three-phase relative permeability. The target of improvements was directed toward to the attainment of two objectives:1) the modification of the equipment to obtain more reliable experimental data and 2) the appropriate interpretation of the data obtained. Special attention was given to the differential pressure and uncertainty measurement in the determination of fluid saturation in the rock samples. Three experiments for three-phase relative permeability were conducted using a sample A and reservoir rock from the Colombian Foothills. Fluid tests included the utilization of synthetic brine, mineral oil, reservoir crude oil and nitrogen. Two runs were conducted at the laboratory conditions while one run was conducted at reservoir conditions. Experimental results of these tests were compared using 16 mathematical models of three-phase relative permeability. For the three-phase relative permeability to oil, the best correlations between experimental data and tests using Blunt, Hustad Hasen, and Baker's models were

  10. Investigating the effect of steam, CO{sub 2}, and surfactant on the recovery of heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Tian, S.; He, S. [China Univ. of Petroleum, Beijing (China). MOE Key Laboratory of Petroleum Engineering; Qu, L. [Shengli Oil Field Co. (China)]|[SINOPEC, Shengli (China)

    2008-10-15

    This paper presented the results of a laboratory study and numerical simulation in which the mechanisms of steam injection with carbon dioxide (CO{sub 2}) and surfactant were investigated. The incremental recoveries of 4 different scenarios were compared and analyzed in terms of phase behaviour. The study also investigated the effect of CO{sub 2} dissolution in oil and water; variation of properties of CO{sub 2}-oil phase equilibrium and CO{sub 2}-water phase equilibrium; variation of viscosity; and, oil volume and interfacial tension (IFT) during the recovery process. The expansion of a steam and CO{sub 2} front was also examined. A field application case of a horizontal well in a heavy oil reservoir in Shengli Oilfield in China was used to determine the actual dynamic performance of the horizontal well and to optimize the injection parameters of the CO{sub 2} and surfactant. The study revealed that oil recovery with the simultaneous injection of steam, CO{sub 2} and surfactant was higher than that of steam injection, steam with CO{sub 2} and steam with surfactant. The improved flow performance in super heavy oil reservoirs could be attributed to CO{sub 2} dissolution in oil which can swell the oil and reduce oil viscosity significantly. The proportion of CO{sub 2} in the free gas phase, oil phase and water phase varies with changes in reservoir pressure and temperature. CO{sub 2} decreases the temperature of the steam slightly, while the surfactant decreases the interfacial tension and helps to improve oil recovery. The study showed that the amount of injected CO{sub 2} and steam has a large effect on heavy oil recovery. Although oil production was found to increase with an increase in injected amounts, the ratio of oil to injected fluids must be considered to achieve optimum recovery. High steam quality and temperature can also improve super heavy oil recovery. The oil recovery was less influenced by the effect of the surfactant than by the effect of CO{sub 2

  11. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, New Mexico

    International Nuclear Information System (INIS)

    Murphy, Mark B.

    1999-01-01

    The overall objective of this project is to demonstrate that a development program based on advanced reservoir management methods can significantly improve oil recovery at the Nash Draw Pool (NDP). The plan includes developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals are (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry

  12. Production Optimization for Two-Phase Flow in an Oil Reservoir

    DEFF Research Database (Denmark)

    Völcker, Carsten; Jørgensen, John Bagterp; Thomsen, Per Grove

    2012-01-01

    framework to increase the production and economic value of an oil reservoir. Wether the objective is to maximize recovery or some financial measure like Net Present Value, the increased production is achieved by manipulation of the well rates and bottom-hole pressures of the injection and production wells....... The optimal water injection rates and production well bottom-hole pressures are computed by solution of a large-scale constrained optimal control problem. The objective is to maximize production by manipulating the well rates and bottom hole pressures of injection and production wells. Optimal control...... settings of injection and production wells are computed by solution of a large scale constrained optimal control problem. We describe a gradient based method to compute the optimal control strategy of the water flooding process. An explicit singly diagonally implicit Runge-Kutta (ESDIRK) method...

  13. Quantifying the clay content with borehole depth and impact on reservoir flow

    Science.gov (United States)

    Sarath Kumar, Aaraellu D.; Chattopadhyay, Pallavi B.

    2017-04-01

    This study focuses on the application of reservoir well log data and 3D transient numerical model for proper optimization of flow dynamics and hydrocarbon potential. Fluid flow through porous media depends on clay content that controls porosity, permeability and pore pressure. The pressure dependence of permeability is more pronounced in tight formations. Therefore, preliminary clay concentration analysis and geo-mechanical characterizations have been done by using wells logs. The assumption of a constant permeability for a reservoir is inappropriate and therefore the study deals with impact of permeability variation for pressure-sensitive formation. The study started with obtaining field data from available well logs. Then, the mathematical models are developed to understand the efficient extraction of oil in terms of reservoir architecture, porosity and permeability. The fluid flow simulations have been done using COMSOL Multiphysics Software by choosing time dependent subsurface flow module that is governed by Darcy's law. This study suggests that the reservoir should not be treated as a single homogeneous structure with unique porosity and permeability. The reservoir parameters change with varying clay content and it should be considered for effective planning and extraction of oil. There is an optimum drawdown for maximum production with varying permeability in a reservoir.

  14. Insights into the Anaerobic Biodegradation Pathway of n-Alkanes in Oil Reservoirs by Detection of Signature Metabolites

    Science.gov (United States)

    Bian, Xin-Yu; Maurice Mbadinga, Serge; Liu, Yi-Fan; Yang, Shi-Zhong; Liu, Jin-Feng; Ye, Ru-Qiang; Gu, Ji-Dong; Mu, Bo-Zhong

    2015-01-01

    Anaerobic degradation of alkanes in hydrocarbon-rich environments has been documented and different degradation strategies proposed, of which the most encountered one is fumarate addition mechanism, generating alkylsuccinates as specific biomarkers. However, little is known about the mechanisms of anaerobic degradation of alkanes in oil reservoirs, due to low concentrations of signature metabolites and lack of mass spectral characteristics to allow identification. In this work, we used a multidisciplinary approach combining metabolite profiling and selective gene assays to establish the biodegradation mechanism of alkanes in oil reservoirs. A total of twelve production fluids from three different oil reservoirs were collected and treated with alkali; organic acids were extracted, derivatized with ethanol to form ethyl esters and determined using GC-MS analysis. Collectively, signature metabolite alkylsuccinates of parent compounds from C1 to C8 together with their (putative) downstream metabolites were detected from these samples. Additionally, metabolites indicative of the anaerobic degradation of mono- and poly-aromatic hydrocarbons (2-benzylsuccinate, naphthoate, 5,6,7,8-tetrahydro-naphthoate) were also observed. The detection of alkylsuccinates and genes encoding for alkylsuccinate synthase shows that anaerobic degradation of alkanes via fumarate addition occurs in oil reservoirs. This work provides strong evidence on the in situ anaerobic biodegradation mechanisms of hydrocarbons by fumarate addition. PMID:25966798

  15. Advanced reservoir characterization for improved oil recovery in a New Mexico Delaware basin project

    Energy Technology Data Exchange (ETDEWEB)

    Martin, F.D.; Kendall, R.P.; Whitney, E.M. [Dave Martin and Associates, Inc., Socorro, NM (United States)] [and others

    1997-08-01

    The Nash Draw Brushy Canyon Pool in Eddy County, New Mexico is a field demonstration site in the Department of Energy Class III program. The basic problem at the Nash Draw Pool is the low recovery typically observed in similar Delaware fields. By comparing a control area using standard infill drilling techniques to a pilot area developed using advanced reservoir characterization methods, the goal of the project is to demonstrate that advanced technology can significantly improve oil recovery. During the first year of the project, four new producing wells were drilled, serving as data acquisition wells. Vertical seismic profiles and a 3-D seismic survey were acquired to assist in interwell correlations and facies prediction. Limited surface access at the Nash Draw Pool, caused by proximity of underground potash mining and surface playa lakes, limits development with conventional drilling. Combinations of vertical and horizontal wells combined with selective completions are being evaluated to optimize production performance. Based on the production response of similar Delaware fields, pressure maintenance is a likely requirement at the Nash Draw Pool. A detailed reservoir model of pilot area was developed, and enhanced recovery options, including waterflooding, lean gas, and carbon dioxide injection, are being evaluated.

  16. Feasibility of using electrical downhole heaters in Faja heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Rodriguez, R.; Bashbush, J.L.; Rincon, A. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Schlumberger, Sugar Land, TX (United States)

    2008-10-15

    Numerical models were used to examine the effect of downhole heaters in enhanced oil recovery (EOR) processes in Venezuela's Orinoco reservoir. The downhole heaters were equipped with mineral-insulated cables that allowed alternating currents to flow between 2 conductors packed in a resistive core composed of polymers and graphite. The heaters were used in conjunction with steam assisted gravity drainage (SAGD) processes and also used in horizontal wells for limited amounts of time in order to accelerate production and pressure declines. The models incorporated the petrophysical and fluid characteristics of the Ayacucho area in the Faja del Orinoco. A compositional-thermal simulator was used to describe heat and fluid flow within the reservoir. A total of 8 scenarios were used to examine the electrical heaters with horizontal and vertical wells with heaters of various capacities. Results of the study were then used in an economic analysis of capitalized and operating costs. Results of the study showed that downhole heaters are an economically feasible EOR option for both vertical and horizontal wells. Use of the heaters prior to SAGD processes accelerated production and achieved higher operational efficiencies. 5 refs., 9 tabs., 15 figs.

  17. Forecasting of reservoir pressures of oil and gas bearing complexes in northern part of West Siberia for safety oil and gas deposits exploration and development

    Science.gov (United States)

    Gorbunov, P. A.; Vorobyov, S. V.

    2017-10-01

    In the paper the features of reservoir pressures changes in the northern part of West Siberian oil-and gas province are described. This research is based on the results of hydrodynamic studies in prospecting and explorating wells in Yamal-Nenets Autonomous District. In the Cenomanian, Albian, Aptian and in the top of Neocomian deposits, according to the research, reservoir pressure is usually equal to hydrostatic pressure. At the bottom of the Neocomian and Jurassic deposits zones with abnormally high reservoir pressures (AHRP) are distinguished within Gydan and Yamal Peninsula and in the Nadym-Pur-Taz interfluve. Authors performed the unique zoning of the territory of the Yamal-Nenets Autonomous District according to the patterns of changes of reservoir pressures in the section of the sedimentary cover. The performed zoning and structural modeling allow authors to create a set of the initial reservoir pressures maps for the main oil and gas bearing complexes of the northern part of West Siberia. The results of the survey should improve the efficiency of exploration drilling by preventing complications and accidents during this operation in zones with abnormally high reservoir pressures. In addition, the results of the study can be used to estimate gas resources within prospective areas of Yamal-Nenets Autonomous District.

  18. Overview of naturally permeable fractured reservoirs in the central and southern Upper Rhine Graben: Insights from geothermal wells

    OpenAIRE

    Vidal , Jeanne; Genter , Albert

    2018-01-01

    International audience; Since the 1980′s, more than 15 geothermal wells have been drilled in the Upper Rhine Graben (URG), representing more than 60 km of drill length. Although some early concepts were related to purely matrix-porosity reservoirs or Hot Dry Rock systems, most projects in the URG are currently exploiting the geothermal resources that are trapped in fracture networks at the base of the sedimentary cover and in the granitic basement. Lessons-learnt from the European EGS referen...

  19. Effects of Formation Damage on Productivity of Underground Gas Storage Reservoirs

    Directory of Open Access Journals (Sweden)

    C.I.C. Anyadiegwu

    2013-12-01

    Full Text Available Analysis of the effects of formation damage on the productivity of gas storage reservoirs was performed with depleted oil reservoir (OB-02, located onshore, Niger Delta, Nigeria. Information on the reservoir and the fluids from OB-02 were collected and used to evaluate the deliverabilities of the gas storage reservoir over a 10-year period of operation. The results obtained were used to plot graphs of deliverability against permeability and skin respectively. The graphs revealed that as the permeability decreased, the skin increased, and hence a decrease in deliverability of gas from the reservoir during gas withdrawal. Over the ten years of operating the reservoir for gas storage, the deliverability and permeability which were initially 2.7 MMscf/d and 50 mD, with a skin of 0.2, changed to new values of 0.88 MMscf/d and 24 mD with the skin as 4.1 at the tenth year.

  20. Numerical Simulation Study on Steam-Assisted Gravity Drainage Performance in a Heavy Oil Reservoir with a Bottom Water Zone

    Directory of Open Access Journals (Sweden)

    Jun Ni

    2017-12-01

    Full Text Available In the Pikes Peak oil field near Lloydminster, Canada, a significant amount of heavy oil reserves is located in reservoirs with a bottom water zone. The properties of the bottom water zone and the operation parameters significantly affect oil production performance via the steam-assisted gravity drainage (SAGD process. Thus, in order to develop this type of heavy oil resource, a full understanding of the effects of these properties is necessary. In this study, the numerical simulation approach was applied to study the effects of properties in the bottom water zone in the SAGD process, such as the initial gas oil ratio, the thickness of the reservoir, and oil saturation of the bottom water zone. In addition, some operation parameters were studied including the injection pressure, the SAGD well pair location, and five different well patterns: (1 two corner wells, (2 triple wells, (3 downhole water sink well, (4 vertical injectors with a horizontal producer, and (5 fishbone well. The numerical simulation results suggest that the properties of the bottom water zone affect production performance extremely. First, both positive and negative effects were observed when solution gas exists in the heavy oil. Second, a logarithmical relationship was investigated between the bottom water production ratio and the thickness of the bottom water zone. Third, a non-linear relation was obtained between the oil recovery factor and oil saturation in the bottom water zone, and a peak oil recovery was achieved at the oil saturation rate of 30% in the bottom water zone. Furthermore, the operation parameters affected the heavy oil production performance. Comparison of the well patterns showed that the two corner wells and the triple wells patterns obtained the highest oil recovery factors of 74.71% and 77.19%, respectively, which are almost twice the oil recovery factors gained in the conventional SAGD process (47.84%. This indicates that the optimized SAGD process

  1. Determination of residual oil saturation from time-lapse pulsed neutron capture logs in a large sandstone reservoir

    International Nuclear Information System (INIS)

    Syed, E.V.; Salaita, G.N.; McCaffery, F.G.

    1991-01-01

    Cased hole logging with pulsed neutron tools finds extensive use for identifying zones of water breakthrough and monitoring oil-water contacts in oil reservoirs being depleted by waterflooding or natural water drive. Results of such surveys then find direct use for planning recompletions and water shutoff treatments. Pulsed neutron capture (PNC) logs are useful for estimating water saturation changes behind casing in the presence of a constant, high-salinity environment. PNC log surveys run at different times, i.e., in a time-lapse mode, are particularly amenable to quantitative analysis. The combined use of the original open hole and PNC time-lapse log information can then provide information on remaining or residual oil saturations in a reservoir. This paper reports analyses of historical pulsed neutron capture log data to assess residual oil saturation in naturally water-swept zones for selected wells from a large sandstone reservoir in the Middle East. Quantitative determination of oil saturations was aided by PNC log information obtained from a series of tests conducted in a new well in the same field

  2. Microbial diversity in methanogenic hydrocarbon-degrading enrichment cultures isolated from a water-flooded oil reservoir (Dagang oil field, China)

    Science.gov (United States)

    Jiménez, Núria; Cai, Minmin; Straaten, Nontje; Yao, Jun; Richnow, Hans H.; Krüger, Martin

    2015-04-01

    Microbial transformation of oil to methane is one of the main degradation processes taking place in oil reservoirs, and it has important consequences as it negatively affects the quality and economic value of the oil. Nevertheless, methane could constitute a recovery method of carbon from exhausted reservoirs. Previous studies combining geochemical and isotopic analysis with molecular methods showed evidence for in situ methanogenic oil degradation in the Dagang oil field, China (Jiménez et al., 2012). However, the main key microbial players and the underlying mechanisms are still relatively unknown. In order to better characterize these processes and identify the main microorganisms involved, laboratory biodegradation experiments under methanogenic conditions were performed. Microcosms were inoculated with production and injection waters from the reservoir, and oil or 13C-labelled single hydrocarbons (e.g. n-hexadecane or 2-methylnaphthalene) were added as sole substrates. Indigenous microbiota were able to extensively degrade oil within months, depleting most of the n-alkanes in 200 days, and producing methane at a rate of 76 ± 6 µmol day-1 g-1 oil added. They could also produce heavy methane from 13C-labeled 2-methylnaphthalene, suggesting that further methanogenesis may occur from the aromatic and polyaromatic fractions of Dagang reservoir fluids. Microbial communities from oil and 2-methyl-naphthalene enrichment cultures were slightly different. Although, in both cases Deltaproteobacteria, mainly belonging to Syntrophobacterales (e.g. Syntrophobacter, Smithella or Syntrophus) and Clostridia, mostly Clostridiales, were among the most represented taxa, Gammaproteobacteria could be only identified in oil-degrading cultures. The proportion of Chloroflexi, exclusively belonging to Anaerolineales (e.g. Leptolinea, Bellilinea) was considerably higher in 2-methyl-naphthalene degrading cultures. Archaeal communities consisted almost exclusively of representatives of

  3. Geochemical controls of the oils acidity in petroleum reservoirs; Controles geochimiques de l'acidite des huiles dans les reservoirs petroliers

    Energy Technology Data Exchange (ETDEWEB)

    Rouquette, N.

    2004-12-01

    Within the framework of this thesis, we were interested in the study of acid oils. Thus, after having developed an analytical method to separate acids from crude oils, this one was applied to the analysis of several series of acid oils presenting various degrees of biodegradation. In the first chapter devoted to their molecular study, it was shown that the alteration of the organic matter proceeds according to a quasi-stepwise order and that the major part of the carboxylic acids appeared as an Unresolved Complex Mixture. The only identified resolved compounds were apparently not formed by biodegradation of the oil in place but rather seem either to have been incorporated during oil migration, or to correspond to compounds initially present in the reservoir rock. Among those, we isolated and identified by NMR a new higher plant tri-terpenic derivative, the 24-nor,28-lupanoic acid. In the second chapter, a new method to evaluate acidity, applicable to small quantities of oil, was developed. This one is based on the methylation of the acid species by iodo-methane marked with carbon 13. In the case of a series from the Gulf of Guinea tested initially, the enrichment after labelling presents a perfect correlation with the values of acidity measured by the TAN method (for 'Total Acid Number'). The isotopic labelling method was applied later to a broader range of oil samples. As a whole, a linear correlation seems to exist between {sup 13}C labelling and TAN index, which lets consider that this method could represent an interesting alternative to the measurement of the TAN index in oil exploration. (author)

  4. Reservoir Identification: Parameter Characterization or Feature Classification

    Science.gov (United States)

    Cao, J.

    2017-12-01

    The ultimate goal of oil and gas exploration is to find the oil or gas reservoirs with industrial mining value. Therefore, the core task of modern oil and gas exploration is to identify oil or gas reservoirs on the seismic profiles. Traditionally, the reservoir is identify by seismic inversion of a series of physical parameters such as porosity, saturation, permeability, formation pressure, and so on. Due to the heterogeneity of the geological medium, the approximation of the inversion model and the incompleteness and noisy of the data, the inversion results are highly uncertain and must be calibrated or corrected with well data. In areas where there are few wells or no well, reservoir identification based on seismic inversion is high-risk. Reservoir identification is essentially a classification issue. In the identification process, the underground rocks are divided into reservoirs with industrial mining value and host rocks with non-industrial mining value. In addition to the traditional physical parameters classification, the classification may be achieved using one or a few comprehensive features. By introducing the concept of seismic-print, we have developed a new reservoir identification method based on seismic-print analysis. Furthermore, we explore the possibility to use deep leaning to discover the seismic-print characteristics of oil and gas reservoirs. Preliminary experiments have shown that the deep learning of seismic data could distinguish gas reservoirs from host rocks. The combination of both seismic-print analysis and seismic deep learning is expected to be a more robust reservoir identification method. The work was supported by NSFC under grant No. 41430323 and No. U1562219, and the National Key Research and Development Program under Grant No. 2016YFC0601

  5. Geologic storage of carbon dioxide and enhanced oil recovery. I. Uncertainty quantification employing a streamline based proxy for reservoir flow simulation

    International Nuclear Information System (INIS)

    Kovscek, A.R.; Wang, Y.

    2005-01-01

    Carbon dioxide (CO 2 ) is already injected into a limited class of reservoirs for oil recovery purposes; however, the engineering design question for simultaneous oil recovery and storage of anthropogenic CO 2 is significantly different from that of oil recovery alone. Currently, the volumes of CO 2 injected solely for oil recovery are minimized due to the purchase cost of CO 2 . If and when CO 2 emissions to the atmosphere are managed, it will be necessary to maximize simultaneously both economic oil recovery and the volumes of CO 2 emplaced in oil reservoirs. This process is coined 'cooptimization'. This paper proposes a work flow for cooptimization of oil recovery and geologic CO 2 storage. An important component of the work flow is the assessment of uncertainty in predictions of performance. Typical methods for quantifying uncertainty employ exhaustive flow simulation of multiple stochastic realizations of the geologic architecture of a reservoir. Such approaches are computationally intensive and thereby time consuming. An analytic streamline based proxy for full reservoir simulation is proposed and tested. Streamline trajectories represent the three-dimensional velocity field during multiphase flow in porous media and so are useful for quantifying the similarity and differences among various reservoir models. The proxy allows rational selection of a representative subset of equi-probable reservoir models that encompass uncertainty with respect to true reservoir geology. The streamline approach is demonstrated to be thorough and rapid

  6. Integrated petrophysical approach for determining reserves and reservoir characterization to optimize production of oil sands in northeastern Alberta

    Energy Technology Data Exchange (ETDEWEB)

    Anderson, A.; Koch, J. [Weatherford Canada Partnership, Bonneyville, AB (Canada)

    2008-10-15

    This study used logging data, borehole imaging data, dipole sonic and magnetic resonance data to study a set of 6 wells in the McMurray Formation of northeastern Alberta. The data sets were used to understand the geologic settings, fluid properties, and rock properties of the area's geology as well as to more accurately estimate its reservoir and production potential. The study also incorporated data from electric, nuclear and acoustic measurements. A shaly sand analysis was used to provide key reservoir petrophysical data. Image data in the study was used to characterize the heterogeneity and permeability of the reservoir in order to optimize production. Results of the shaly sand analysis were then combined with core data and nuclear resonance data in order to determine permeability and lithology-independent porosity. Data sets were used to iteratively refine an integrated petrophysical analysis. Results of the analysis indicated that the depositional environment in which the wells were located did not match a typical fluvial-estuarine sands environment. A further interpretation of all data indicated that the wells were located in a shoreface environment. It was concluded that the integration of petrophysical measurements can enable geoscientists to more accurately characterize sub-surface environments. 3 refs., 7 figs.

  7. An Integrated Approach to Characterizing Bypassed Oil in Heterogeneous and Fractured Reservoirs Using Partitioning Tracers

    Energy Technology Data Exchange (ETDEWEB)

    Akhil Datta-Gupta

    2006-12-31

    . The approach is very fast and avoids much of the subjective judgments and time-consuming trial-and-errors associated with manual history matching. We demonstrate the power and utility of our approach using a synthetic example and two field examples. We have also explored the use of a finite difference reservoir simulator, UTCHEM, for field-scale design and optimization of partitioning interwell tracer tests. The finite-difference model allows us to include detailed physics associated with reactive tracer transport, particularly those related with transverse and cross-streamline mechanisms. We have investigated the potential use of downhole tracer samplers and also the use of natural tracers for the design of partitioning tracer tests. Finally, we discuss several alternative ways of using partitioning interwell tracer tests (PITTs) in oil fields for the calculation of oil saturation, swept pore volume and sweep efficiency, and assess the accuracy of such tests under a variety of reservoir conditions.

  8. The Multi-Porosity Multi-Permeability and Electrokinetic Natures of Shales and Their Effects in Hydraulic Fracturing of Unconventional Shale Reservoirs

    Science.gov (United States)

    Liu, C.; Hoang, S. K.; Tran, M. H.; Abousleiman, Y. N.

    2013-12-01

    Imaging studies of unconventional shale reservoir rocks have recently revealed the multi-porosity multi-permeability nature of these intricate formations. In particular, the porosity spectrum of shale reservoir rocks often comprises of the nano-porosity in the organic matters, the inter-particle micro-porosity, and the macroscopic porosity of the natural fracture network. Shale is also well-known for its chemically active behaviors, especially shrinking and swelling when exposed to aqueous solutions, as the results of pore fluid exchange with external environment due to the difference in electro-chemical potentials. In this work, the effects of natural fractures and electrokinetic nature of shale on the formation responses during hydraulic fracturing are examined using the dual-poro-chemo-electro-elasticity approach which is a generalization of the classical Biot's poroelastic formulation. The analyses show that the presence of natural fractures can substantially increase the leak-off rate of fracturing fluid into the formation and create a larger region of high pore pressure near the fracture face as shown in Fig.1a. Due to the additional fluid invasion, the naturally fractured shale swells up more and the fracture aperture closes faster compared to an intrinsically low permeability non-fractured shale formation as shown in Fig.1b. Since naturally fractured zones are commonly targeted as pay zones, it is important to account for the faster fracture closing rate in fractured shales in hydraulic fracturing design. Our results also show that the presence of negative fixed charges on the surface of clay minerals creates an osmotic pressure at the interface of the shale and the external fluid as shown in Fig.1c. This additional Donnan-induced pore pressure can result in significant tensile effective stresses and tensile damage in the shale as shown in Fig.1d. The induced tensile damage can exacerbate the problem of proppant embedment resulting in more fracture closure

  9. Eos modeling and reservoir simulation study of bakken gas injection improved oil recovery in the elm coulee field, Montana

    Science.gov (United States)

    Pu, Wanli

    The Bakken Formation in the Williston Basin is one of the most productive liquid-rich unconventional plays. The Bakken Formation is divided into three members, and the Middle Bakken Member is the primary target for horizontal wellbore landing and hydraulic fracturing because of its better rock properties. Even with this new technology, the primary recovery factor is believed to be only around 10%. This study is to evaluate various gas injection EOR methods to try to improve on that low recovery factor of 10%. In this study, the Elm Coulee Oil Field in the Williston Basin was selected as the area of interest. Static reservoir models featuring the rock property heterogeneity of the Middle Bakken Member were built, and fluid property models were built based on Bakken reservoir fluid sample PVT data. By employing both compositional model simulation and Todd-Longstaff solvent model simulation methods, miscible gas injections were simulated and the simulations speculated that oil recovery increased by 10% to 20% of OOIP in 30 years. The compositional simulations yielded lower oil recovery compared to the solvent model simulations. Compared to the homogeneous model, the reservoir model featuring rock property heterogeneity in the vertical direction resulted in slightly better oil recovery, but with earlier CO2 break-through and larger CO2 production, suggesting that rock property heterogeneity is an important property for modeling because it has a big effect on the simulation results. Long hydraulic fractures shortened CO2 break-through time greatly and increased CO 2 production. Water-alternating-gas injection schemes and injection-alternating-shut-in schemes can provide more options for gas injection EOR projects, especially for gas production management. Compared to CO2 injection, separator gas injection yielded slightly better oil recovery, meaning separator gas could be a good candidate for gas injection EOR; lean gas generated the worst results. Reservoir

  10. Volume 5: An evaluation of known remaining oil resources in piercement salt dome reservoirs in the Gulf of Mexico

    Energy Technology Data Exchange (ETDEWEB)

    Mohan, H.; Rogers, M.; Becker, A.; Biglarbigi, K.; Brashear, J. [ICF Kaiser-ICF Information Technology, Inc., Fairfax, VA (United States)

    1996-08-01

    The US Department of Energy, Office of Fossil Energy (DOE/FE) has among its missions the facilitation of the development of required technologies to maximize the potential economic recovery of domestic oil and gas resources--both offshore and onshore, especially from Federal lands. In planning its activities, the DOE/FE relies on a number of comprehensive analytical systems in order to target and prioritize its research and development (R and D) activities and to estimate the benefits of its programs. DOE/FE`s analytical system, however, lacks the capability to assess the potential of future technology advances on the exploration, development, and production of crude oil resources in the Federal offshore of the Gulf of Mexico. The objective of the present effort is to develop an analytical system to characterize a portion of the Gulf offshore resources--the remaining unrecovered mobile oil resource associated with piercement salt dome reservoirs (hereafter referred to as salt dome reservoirs), and to evaluate additional recovery potential and related economic benefits that could result from the application of improved technologies. As part of the present effort a comprehensive analytical system has been developed for the characterization and evaluation of unrecovered mobile oil associated with the salt dome reservoirs in Federal offshore Gulf of Mexico. The system consists of a comprehensive database containing detailed rock and fluid properties, geologic information, and production and development history for 1,289 major fields and reservoirs representing an estimated 60% of the salt dome resources in the region. In addition, two separate methodologies and related economic and predictive models have been developed for the evaluation of applicable recovery processes. The system is intended for use as part of DOE`s Tertiary Oil Recovery Information System (TORIS).

  11. Reservoir model for the Alameda Central waterflood

    Energy Technology Data Exchange (ETDEWEB)

    Randall, T E

    1968-01-01

    The basic approach used in developing the model to characterize the Alameda Central Unit Waterflood assumes continuity of the reservoir mechanics with time. The past performance was analyzed to describe the reservoir and future performance was assumed to follow the established patterns. To develop a mathematical picture of the Alameda Central Unit reservoir, a two-dimensional single-phase steady-state model was used in conjunction with material balance calculations, real-time conversion methods and oil-water interface advance calculations. The model was developed to optimize water injection allocation, determine the configuration of the frontal advance and evaluate the success of the waterflood. The model also provides a basis for continuing review and revision of the basic concepts of reservoir operation. The results of the reservoir study have confirmed the apparent lack of permeability orientation in the pool and indicate that the waterflood is progressing better than originally anticipated.

  12. Impact of an indigenous microbial enhanced oil recovery field trial on microbial community structure in a high pour-point oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Zhang, Fan; Zhang, Xiao-Tao; Hou, Du-Jie [China Univ. of Geosciences, Beijing (China). The Key Lab. of Marine Reservoir Evolution and Hydrocarbon Accumulation Mechanism; She, Yue-Hui [Yangtze Univ., Jingzhou, Hubei (China). College of Chemistry and Environmental Engineering; Huazhong Univ. of Science and Technology, Wuhan (China). College of Life Science and Technology; Li, Hua-Min [Beijing Bioscience Research Center (China); Shu, Fu-Chang; Wang, Zheng-Liang [Yangtze Univ., Jingzhou, Hubei (China). College of Chemistry and Environmental Engineering; Yu, Long-Jiang [Huazhong Univ. of Science and Technology, Wuhan (China). College of Life Science and Technology

    2012-08-15

    Based on preliminary investigation of microbial populations in a high pour-point oil reservoir, an indigenous microbial enhanced oil recovery (MEOR) field trial was carried out. The purpose of the study is to reveal the impact of the indigenous MEOR process on microbial community structure in the oil reservoir using 16Sr DNA clone library technique. The detailed monitoring results showed significant response of microbial communities during the field trial and large discrepancies of stimulated microorganisms in the laboratory and in the natural oil reservoir. More specifically, after nutrients injection, the original dominant populations of Petrobacter and Alishewanella in the production wells almost disappeared. The expected desirable population of Pseudomonas aeruginosa, determined by enrichment experiments in laboratory, was stimulated successfully in two wells of the five monitored wells. Unexpectedly, another potential population of Pseudomonas pseudoalcaligenes which were not detected in the enrichment culture in laboratory was stimulated in the other three monitored production wells. In this study, monitoring of microbial community displayed a comprehensive alteration of microbial populations during the field trial to remedy the deficiency of culture-dependent monitoring methods. The results would help to develop and apply more MEOR processes. (orig.)

  13. Impact of an indigenous microbial enhanced oil recovery field trial on microbial community structure in a high pour-point oil reservoir.

    Science.gov (United States)

    Zhang, Fan; She, Yue-Hui; Li, Hua-Min; Zhang, Xiao-Tao; Shu, Fu-Chang; Wang, Zheng-Liang; Yu, Long-Jiang; Hou, Du-Jie

    2012-08-01

    Based on preliminary investigation of microbial populations in a high pour-point oil reservoir, an indigenous microbial enhanced oil recovery (MEOR) field trial was carried out. The purpose of the study is to reveal the impact of the indigenous MEOR process on microbial community structure in the oil reservoir using 16Sr DNA clone library technique. The detailed monitoring results showed significant response of microbial communities during the field trial and large discrepancies of stimulated microorganisms in the laboratory and in the natural oil reservoir. More specifically, after nutrients injection, the original dominant populations of Petrobacter and Alishewanella in the production wells almost disappeared. The expected desirable population of Pseudomonas aeruginosa, determined by enrichment experiments in laboratory, was stimulated successfully in two wells of the five monitored wells. Unexpectedly, another potential population of Pseudomonas pseudoalcaligenes which were not detected in the enrichment culture in laboratory was stimulated in the other three monitored production wells. In this study, monitoring of microbial community displayed a comprehensive alteration of microbial populations during the field trial to remedy the deficiency of culture-dependent monitoring methods. The results would help to develop and apply more MEOR processes.

  14. Analytical solution for Joule-Thomson cooling during CO2 geo-sequestration in depleted oil and gas reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Mathias, S.A.; Gluyas, J.G.; Oldenburg, C.M.; Tsang, C.-F.

    2010-05-21

    Mathematical tools are needed to screen out sites where Joule-Thomson cooling is a prohibitive factor for CO{sub 2} geo-sequestration and to design approaches to mitigate the effect. In this paper, a simple analytical solution is developed by invoking steady-state flow and constant thermophysical properties. The analytical solution allows fast evaluation of spatiotemporal temperature fields, resulting from constant-rate CO{sub 2} injection. The applicability of the analytical solution is demonstrated by comparison with non-isothermal simulation results from the reservoir simulator TOUGH2. Analysis confirms that for an injection rate of 3 kg s{sup -1} (0.1 MT yr{sup -1}) into moderately warm (>40 C) and permeable formations (>10{sup -14} m{sup 2} (10 mD)), JTC is unlikely to be a problem for initial reservoir pressures as low as 2 MPa (290 psi).

  15. Surrogate reservoir models for CSI well probabilistic production forecast

    Directory of Open Access Journals (Sweden)

    Saúl Buitrago

    2017-09-01

    Full Text Available The aim of this work is to present the construction and use of Surrogate Reservoir Models capable of accurately predicting cumulative oil production for every well stimulated with cyclic steam injection at any given time in a heavy oil reservoir in Mexico considering uncertain variables. The central composite experimental design technique was selected to capture the maximum amount of information from the model response with a minimum number of reservoir models simulations. Four input uncertain variables (the dead oil viscosity with temperature, the reservoir pressure, the reservoir permeability and oil sand thickness hydraulically connected to the well were selected as the ones with more impact on the initial hot oil production rate according to an analytical production prediction model. Twenty five runs were designed and performed with the STARS simulator for each well type on the reservoir model. The results show that the use of Surrogate Reservoir Models is a fast viable alternative to perform probabilistic production forecasting of the reservoir.

  16. Advanced reservoir characterization in the Antelope Shale to establish the viability of CO2 enhanced oil recovery in California`s Monterey Formation siliceous shales. Annual report, February 7, 1997--February 6, 1998

    Energy Technology Data Exchange (ETDEWEB)

    Morea, M.F.

    1998-06-01

    The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO{sub 2} enhanced oil recovery project in the antelope Shale in Buena Vista Hills Field. The proposed pilot consists of four existing producers on 20 acre spacing with a new 10 acre infill well drilled as the pilot CO{sub 2} injector. Most of the reservoir characterization during Phase 1 of the project will be performed using data collected in the pilot pattern wells. During this period the following tasks have been completed: laboratory wettability; specific permeability; mercury porosimetry; acoustic anisotropy; rock mechanics analysis; core description; fracture analysis; digital image analysis; mineralogical analysis; hydraulic flow unit analysis; petrographic and confocal thin section analysis; oil geochemical fingerprinting; production logging; carbon/oxygen logging; complex lithologic log analysis; NMR T2 processing; dipole shear wave anisotropy logging; shear wave vertical seismic profile processing; structural mapping; and regional tectonic synthesis. Noteworthy technological successes for this reporting period include: (1) first (ever) high resolution, crosswell reflection images of SJV sediments; (2) first successful application of the TomoSeis acquisition system in siliceous shales; (3) first detailed reservoir characterization of SJV siliceous shales; (4) first mineral based saturation algorithm for SJV siliceous shales, and (5) first CO{sub 2} coreflood experiments for siliceous shale. Preliminary results from the CO{sub 2} coreflood experiments (2,500 psi) suggest that significant oil is being produced from the siliceous shale.

  17. Polymer as permeability modifier in porous media for enhanced oil recovery

    Science.gov (United States)

    Parsa, Shima; Weitz, David

    2017-11-01

    We use confocal microscopy to directly visualize the changes in morphology and mobilization of trapped oil ganglia within a 3D micromodel of porous media upon polymer flooding. Enhanced oil recovery is achieved in polymer flooding with large molecular weight at concentrations close or higher than a critical concentration of polymer. We also measure the fluctuations of the velocity of the displacing fluid and show that the velocities change upon polymer flooding in the whole medium. The changes in the fluid velocities are heterogeneous and vary in different pores, hence only providing enough pressure gradient across a few of the trapped oil ganglia and mobilize them. Our measurements show that polymer flooding is an effective method for enhancing oil recovery due to retention of polymer on the solid surfaces and changing the resistances of the available paths to water.

  18. On an inverse source problem for enhanced oil recovery by wave motion maximization in reservoirs

    KAUST Repository

    Karve, Pranav M.

    2014-12-28

    © 2014, Springer International Publishing Switzerland. We discuss an optimization methodology for focusing wave energy to subterranean formations using strong motion actuators placed on the ground surface. The motivation stems from the desire to increase the mobility of otherwise entrapped oil. The goal is to arrive at the spatial and temporal description of surface sources that are capable of maximizing mobility in the target reservoir. The focusing problem is posed as an inverse source problem. The underlying wave propagation problems are abstracted in two spatial dimensions, and the semi-infinite extent of the physical domain is negotiated by a buffer of perfectly-matched-layers (PMLs) placed at the domain’s truncation boundary. We discuss two possible numerical implementations: Their utility for deciding the tempo-spatial characteristics of optimal wave sources is shown via numerical experiments. Overall, the simulations demonstrate the inverse source method’s ability to simultaneously optimize load locations and time signals leading to the maximization of energy delivery to a target formation.

  19. Identification and evaluation of fluvial-dominated deltaic (Class I oil) reservoirs in Oklahoma. Final report, August 1998

    Energy Technology Data Exchange (ETDEWEB)

    Banken, M.K.

    1998-11-01

    The Oklahoma Geological Survey (OGS), the Geo Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma have engaged in a five-year program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program included a systematic and comprehensive collection and evaluation of information on all FDD oil reservoirs in Oklahoma and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. The execution of this project was approached in phases. The first phase began in January, 1993 and consisted of planning, play identification and analysis, data acquisition, database development, and computer systems design. By the middle of 1994, many of these tasks were completed or nearly finished including the identification of all FDD reservoirs in Oklahoma, data collection, and defining play boundaries. By early 1995, a preliminary workshop schedule had been developed for project implementation and technology transfer activities. Later in 1995, the play workshop and publication series was initiated with the Morrow and the Booch plays. Concurrent with the initiation of the workshop series was the opening of a computer user lab that was developed for use by the petroleum industry. Industry response to the facility initially was slow, but after the first year lab usage began to increase and is sustaining. The remaining six play workshops were completed through 1996 and 1997, with the project ending on December 31, 1997.

  20. Competitive, microbially-mediated reduction of nitrate with sulfide and aromatic oil components in a low-temperature, western Canadian oil reservoir.

    Science.gov (United States)

    Lambo, Adewale J; Noke, Kim; Larter, Steve R; Voordouw, Gerrit

    2008-12-01

    Fields from which oil is produced by injection of sulfate-bearing water often exhibit an increase in sulfide concentration with time (souring). Nitrate added to the injection water lowers the sulfide concentration by the action of sulfide-oxidizing, nitrate-reducing bacteria (SO-NRB). However, the injected nitrate can also be reduced with oil organics by heterotrophic NRB (hNRB). Aqueous volatile fatty acids (VFAs; a mixture of acetate, propionate, and butyrate) are considered important electron donors in this regard. Injection and produced waters from a western Canadian oil field with a low in situ reservoir temperature (30 degrees C) had only 0.1-0.2 mM VFAs. Amendment of these waters with nitrate gave therefore only partial reduction. More nitrate was reduced when 2% (v/v) oil was added, with light oil giving more reduction than heavy oil. GC-MS analysis of in vitro degraded oils and electron balance considerations indicated that toluene served as the primary electron donor for nitrate reduction. The differences in the extent of nitrate reduction were thus related to the toluene content of the light and heavy oil (30 and 5 mM, respectively). Reduction of nitrate with sulfide by SO-NRB always preceded that with oil organics by hNRB, even though microbially catalyzed kinetics with either electron donor were similar. Inhibition of hNRB by sulfide is responsible for this phenomenon. Injected nitrate will thus initially be reduced with sulfide through the action of SO-NRB. However, once sulfide has been eliminated from the near-injection wellbore region, oil organics will be targeted by the action of hNRB. Hence, despite the kinetic advantage of SO-NRB, the nitrate dose required to eliminate sulfide from a reservoir depends on the concentration of hNRB-degradable oil organics, with toluene being the most important in the field under study. Because the toluene concentration is lower in heavy oilthan in light oil, nitrate injection into a heavy-oil-producing field of

  1. Copaiba oil enhances in vitro/in vivo cutaneous permeability and in vivo anti-inflammatory effect of celecoxib.

    Science.gov (United States)

    Quiñones, Oliesia Gonzalez; Hossy, Bryan Hudson; Padua, Tatiana Almeida; Miguel, Nádia Campos de Oliveira; Rosas, Elaine Cruz; Ramos, Mônica Freiman de Souza; Pierre, Maria Bernadete Riemma

    2018-03-29

    The aim of this article was to use copaiba oil (C.O) to improve skin permeability and topical anti-inflammatory activity of celecoxib (Cxb). Formulations containing C.O (1-50%) were associated with Cxb (2%). In vitro skin permeability studies were conducted using porcine ear skin. Histological analysis of the hairless mice skin samples after application of formulations was achieved with the routine haematoxylin/eosin technique. The anti-inflammatory activity was assessed using the AA-induced ear oedema mice model. The formulation containing 25% C.O promoted the highest levels of in vitro Cxb permeation through pig ear skin, retention in the stratum corneum (SC) and epidermis/dermis of pig ear skin in vitro (~5-fold) and hairless mice skin in vivo (~2.0-fold), as compared with the control formulation. At 25%, C.O caused SC disorganization and increased cell infiltration and induced angiogenesis without clear signs of skin irritation. The formulation added to 25% C.O as adjuvant inhibited ear oedema and protein extravasation by 77.51 and 89.7%, respectively, and that it was, respectively, 2.0- and 3.4-fold more efficient than the commercial diethylammonium diclofenac cream gel to suppress these inflammatory parameters. 25% C.O is a potential penetration enhancer for lipophilic drugs like Cxb that can improve cutaneous drug penetration and its anti-inflammatory activity. © 2018 Royal Pharmaceutical Society.

  2. Artificial Neural Network Model for Alkali-Surfactant-Polymer Flooding in Viscous Oil Reservoirs: Generation and Application

    Directory of Open Access Journals (Sweden)

    Si Le Van

    2016-12-01

    Full Text Available Chemical flooding has been widely utilized to recover a large portion of the oil remaining in light and viscous oil reservoirs after the primary and secondary production processes. As core-flood tests and reservoir simulations take time to accurately estimate the recovery performances as well as analyzing the feasibility of an injection project, it is necessary to find a powerful tool to quickly predict the results with a level of acceptable accuracy. An approach involving the use of an artificial neural network to generate a representative model for estimating the alkali-surfactant-polymer flooding performance and evaluating the economic feasibility of viscous oil reservoirs from simulation is proposed in this study. A typical chemical flooding project was referenced for this numerical study. A number of simulations have been made for training on the basis of a base case from the design of 13 parameters. After training, the network scheme generated from a ratio data set of 50%-20%-30% corresponding to the number of samples used for training-validation-testing was selected for estimation with the total coefficient of determination of 0.986 and a root mean square error of 1.63%. In terms of model application, the chemical concentration and injection strategy were optimized to maximize the net present value (NPV of the project at a specific oil price from the just created ANN model. To evaluate the feasibility of the project comprehensively in terms of market variations, a range of oil prices from 30 $/bbl to 60 $/bbl referenced from a real market situation was considered in conjunction with its probability following a statistical distribution on the NPV computation. Feasibility analysis of the optimal chemical injection scheme revealed a variation of profit from 0.42 $MM to 1.0 $MM, corresponding to the changes in oil price. In particular, at the highest possible oil prices, the project can earn approximately 0.61 $MM to 0.87 $MM for a quarter

  3. Evaluation of the permeability of microporous membranes polyamide 6 / clay bentonite for water-oil separation

    International Nuclear Information System (INIS)

    Medeiros, P.S.S.; Medeiros, K.M.; Araujo, E.M.; Lira, H.L.

    2014-01-01

    The petroleum refining industries have faced major problems in relation to the treatment of their effluents before disposal into the environment. Among the conventional technologies treatment of these effluents, the process of oil-water separation by means of membranes has been extensively used, for having enormous potentiality. Therefore, in this study, hybrid membranes of polyamide 6/ bentonite clay were produced by the technique of phase inversion and by precipitation of the solution from the nanocomposites obtained by melt intercalation. The clay was organically modified with the quaternary ammonium salt (Cetremide®). The nanocomposites were obtained from (PA6) with untreated (AST) and treated clay (ACT), which were subsequently characterized by X-ray diffraction (XRD). Already membranes were characterized by XRD, scanning electron microscopy (SEM) and flow measurements. From the XRD results, it was observed an exfoliated and/or partially exfoliated structure for the nanocomposites and for the membranes. From SEM images it was observed that the presence of AST and ACT clays in the polymeric matrix caused changes in membrane morphology and pore formation. The flow with distilled water in the membranes showed a decrease initially and then followed by stability. All membranes tested in the process of separating emulsions of oil in water, particularly those of nanocomposites obtained a significant reduction of oil concentration in the permeate, thus showing that these membranes have a great potential to be applied to the water-oil separation. (author)

  4. FRACTURED PETROLEUM RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Abbas Firoozabadi

    1999-06-11

    The four chapters that are described in this report cover a variety of subjects that not only give insight into the understanding of multiphase flow in fractured porous media, but they provide also major contribution towards the understanding of flow processes with in-situ phase formation. In the following, a summary of all the chapters will be provided. Chapter I addresses issues related to water injection in water-wet fractured porous media. There are two parts in this chapter. Part I covers extensive set of measurements for water injection in water-wet fractured porous media. Both single matrix block and multiple matrix blocks tests are covered. There are two major findings from these experiments: (1) co-current imbibition can be more efficient than counter-current imbibition due to lower residual oil saturation and higher oil mobility, and (2) tight fractured porous media can be more efficient than a permeable porous media when subjected to water injection. These findings are directly related to the type of tests one can perform in the laboratory and to decide on the fate of water injection in fractured reservoirs. Part II of Chapter I presents modeling of water injection in water-wet fractured media by modifying the Buckley-Leverett Theory. A major element of the new model is the multiplication of the transfer flux by the fractured saturation with a power of 1/2. This simple model can account for both co-current and counter-current imbibition and computationally it is very efficient. It can be orders of magnitude faster than a conventional dual-porosity model. Part II also presents the results of water injection tests in very tight rocks of some 0.01 md permeability. Oil recovery from water imbibition tests from such at tight rock can be as high as 25 percent. Chapter II discusses solution gas-drive for cold production from heavy-oil reservoirs. The impetus for this work is the study of new gas phase formation from in-situ process which can be significantly

  5. Enhanced Oil Recovery Using Micron-Size Polyacrylamide Elastic Microspheres (MPEMs): Underlying Mechanisms and Displacement Experiments

    KAUST Repository

    Yao, Chuanjin; Lei, Guanglun; Hou, Jian; Xu, Xiaohong; Wang, Dan; Steenhuis, Tammo S.

    2015-01-01

    Micron-size polyacrylamide elastic microsphere (MPEM) is a newly developed profile control and oil displacement agent for enhanced oil recovery in heterogeneous reservoirs. In this study, laboratory experiments were performed to characterize the viscoelastic properties of MPEMs in brine water. A transparent sandpack micromodel was used to observe the microscopic flow and displacement mechanisms, and parallel-sandpack models were used to investigate the profile control and oil displacement performance using MPEMs in heterogeneous reservoirs. The results indicate that MPEMs almost do not increase the viscosity of injection water and can be conveniently injected using the original water injection pipelines. The microscopic profile control and oil displacement mechanisms of MPEMs in porous media mainly behave as selective-plugging in large pores, fluid diversion after MPEMs plugging, oil drainage caused by MPEMs breakthrough, and the mechanism of oil droplets converging into oil flow. MPEMs have a high plugging strength, which can tolerate a long-term water flushing. MPEMs can selectively enter and plug the large pores and pore-throats in high permeability sandpack, but almost do not damage the low permeability sandpack. MPEMs can effectively divert the water flow from the high permeability sandpack to the low permeability sandpack and improve the sweep efficiency of low permeability sandpack and low permeability area in the high permeability sandpack. The results also confirm the dynamic process of profile control and oil displacement using MPEMs in heterogeneous reservoirs.

  6. Enhanced Oil Recovery Using Micron-Size Polyacrylamide Elastic Microspheres (MPEMs): Underlying Mechanisms and Displacement Experiments

    KAUST Repository

    Yao, Chuanjin

    2015-10-12

    Micron-size polyacrylamide elastic microsphere (MPEM) is a newly developed profile control and oil displacement agent for enhanced oil recovery in heterogeneous reservoirs. In this study, laboratory experiments were performed to characterize the viscoelastic properties of MPEMs in brine water. A transparent sandpack micromodel was used to observe the microscopic flow and displacement mechanisms, and parallel-sandpack models were used to investigate the profile control and oil displacement performance using MPEMs in heterogeneous reservoirs. The results indicate that MPEMs almost do not increase the viscosity of injection water and can be conveniently injected using the original water injection pipelines. The microscopic profile control and oil displacement mechanisms of MPEMs in porous media mainly behave as selective-plugging in large pores, fluid diversion after MPEMs plugging, oil drainage caused by MPEMs breakthrough, and the mechanism of oil droplets converging into oil flow. MPEMs have a high plugging strength, which can tolerate a long-term water flushing. MPEMs can selectively enter and plug the large pores and pore-throats in high permeability sandpack, but almost do not damage the low permeability sandpack. MPEMs can effectively divert the water flow from the high permeability sandpack to the low permeability sandpack and improve the sweep efficiency of low permeability sandpack and low permeability area in the high permeability sandpack. The results also confirm the dynamic process of profile control and oil displacement using MPEMs in heterogeneous reservoirs.

  7. Analysis of nitrogen injection as alternative fluid to steam in heavy oil reservoir; Analise da injecao de nitrogenio como fluido alternativo ao vapor em reservatorio de oleo pesado

    Energy Technology Data Exchange (ETDEWEB)

    Rodrigues, Marcos Allyson Felipe; Galvao, Edney Rafael Viana Pinheiro; Barillas, Jennys Lourdes; Mata, Wilson da; Dutra Junior, Tarcilio Viana [Universidade Federal do Rio Grande do Norte (UFRN), RN (Brazil)

    2012-07-01

    Many of hydrocarbon reserves existing in the world are formed by heavy oils (deg API between 10 and 20). Moreover, several heavy oil fields are mature and, thus, offer great challenges for oil industry. Among the thermal methods used to recover these resources, steam flooding has been the main economically viable alternative. Latent heat carried by steam heats the reservoir, reducing oil viscosity and facilitating the production. This method has many variations and has been studied both theoretically and experimentally (in pilot projects and in full field applications). In order to increase oil recovery and reduce steam injection costs, the injection of alternative fluid has been used on three main ways: alternately, co-injected with steam and after steam injection interruption. The main objective of these injection systems is to reduce the amount of heat supplied to the reservoir, using cheaper fluids and maintaining the same oil production levels. In this paper, the use of N{sub 2} as an alternative fluid to the steam was investigated. The analyzed parameters were oil recoveries and net cumulative oil productions. The reservoir simulation model corresponds to an oil reservoir of 100 m x 100 m x 28 m size, on a Cartesian coordinates system (x, y and z directions). It is a semi synthetic model with some reservoir data similar to those found in Potiguar Basin, Brazil. All studied cases were done using the simulator STARS from CMG (Computer Modelling Group, version 2009.10). It was found that N{sub 2} injection after steam injection interruption achieved the highest net cumulative oil compared to others injection system. Moreover, it was observed that N2 as alternative fluid to steam did not present increase on oil recovery. (author)

  8. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal - Appendix)

    Energy Technology Data Exchange (ETDEWEB)

    Bou-Mikael, Sami

    2002-02-05

    The main objective of the Port Neches Project was to determine the feasibility and producibility of CO2 miscible flooding techniques enhanced with horizontal drilling applied to a Fluvial Dominated Deltaic reservoir. The second was to disseminate the knowledge gained through established Technology Transfer mechanisms to support DOE's programmatic objectives of increasing domestic oil production and reducing abandonment of oil fields.

  9. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal - Appendix); FINAL

    International Nuclear Information System (INIS)

    Bou-Mikael, Sami

    2002-01-01

    The main objective of the Port Neches Project was to determine the feasibility and producibility of CO2 miscible flooding techniques enhanced with horizontal drilling applied to a Fluvial Dominated Deltaic reservoir. The second was to disseminate the knowledge gained through established Technology Transfer mechanisms to support DOE's programmatic objectives of increasing domestic oil production and reducing abandonment of oil fields

  10. Biopolymer system for permeability modification in porous media

    Energy Technology Data Exchange (ETDEWEB)

    Stepp, A.K.; Bryant, R.S.; Llave, F.M. [BMD-Oklahoma, Inc., Bartlesville, OK (United States)] [and others

    1995-12-31

    New technologies are needed to reduce the current high rate of well abandonment. Improved sweep efficiency, reservoir conformance, and permeability modification can have a significant impact on oil recovery processes. Microorganisms can be used to selectively plug high-permeability zones to improve sweep efficiency and impart conformance control. Studies of a promising microbial system for polymer production were conducted to evaluate reservoir conditions in which this system would be effective. Factors which can affect microbial growth and polymer production include salinity, pH, temperature, divalent ions, presence of residual oil, and rock matrix. Flask tests and coreflooding experiments were conducted to optimize and evaluate the effectiveness of this system. Nuclear magnetic resonance imaging (NMRI) was used to visualize microbial polymer production in porous media. Changes in fluid distribution within the pore system of the core were detected.

  11. Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO2 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales

    International Nuclear Information System (INIS)

    Morea, Michael F.

    1999-01-01

    The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO2 enhanced oil recovery project in the Antelope Shale in Buena Vista Hills Field. The Buena Vista Hills pilot CO2 project will demonstrate the economic viability and widespread applicability of CO2 flooding in fractured siliceous shale reservoirs of the San Joaquin Valley. The research consists of four primary work processes: (1) Reservoir Matrix and Fluid Characterization; (2) Fracture characterization; (3) reservoir Modeling and Simulation; and (4) CO2 Pilot Flood and Evaluation. Work done in these areas is subdivided into two phases or budget periods. The first phase of the project will focus on the application of a variety of advanced reservoir characterization techniques to determine the production characteristics of the Antelope Shale reservoir. Reservoir models based on the results of the characterization work will be used to evaluate how the reservoir will respond to secondary recovery and EOR processes. The second phase of the project will include the implementation and evaluation of an advanced enhanced oil recovery (EOR) pilot in the United Anticline (West Dome) of the Buena Vista Hills Field

  12. Characterization of dynamic change of Fan-delta reservoir properties in water-drive development

    Energy Technology Data Exchange (ETDEWEB)

    Wu Shenghe; Xiong Qihua; Liu Yuhong [Univ. of Petroleum Changping, Beijing (China)

    1997-08-01

    Fan-delta reservoir in Huzhuangji oil field of east China, is a typical highly heterogeneous reservoir. The oil field has been developed by water-drive for 10 years, but the oil recovery is less than 12%, and water cut is over 90%, resulting from high heterogeneity and serious dynamic change of reservoir properties. This paper aims at the study of dynamic change of reservoir properties in water-drive development. Through quantitative imaging analysis and mercury injection analysis of cores from inspection wells, the dynamic change of reservoir pore structure in water-drive development was studied. The results show that the {open_quotes}large pore channels{close_quotes} develop in distributary channel sandstone and become larger in water-drive development, resulting in more serious pore heterogeneity. Through reservoir sensitivity experiments, the rock-fluid reaction in water-drive development is studied. The results show the permeability of some distal bar sandstone and deserted channel sandstone becomes lower due to swelling of I/S clay minerals in pore throats. OD the other hand, the permeability of distributary channel and mouth bar sandstone become larger because the authigenic Koalinites in pore throats are flushed away with the increase of flow rate of injection water. Well-logging analysis of flooded reservoirs are used to study the dynamic change of reservoir properties in various flow units. The distribution of remaining oil is closely related to the types and distribution of flow units.

  13. Improved heavy oil recovery by low rate waterflooding

    Energy Technology Data Exchange (ETDEWEB)

    Mai, A. [Laricina Energy Ltd., Calgary, AB (Canada); Kantzas, A. [Calgary Univ., AB (Canada). Tomographic Imaging and Porous Media Laboratory

    2008-10-15

    Waterflooding techniques are frequently used to recover oil in low viscosity or marginal heavy oil reservoirs. This paper described a low-rate waterflooding oil recovery mechanism. The mechanism was determined by examining the effect of sand permeability on the impact of viscous force contributions. Changes in permeability and injection rates parameters were studied in order to evaluate the significance of imbibition, and a method of quantifying the effect of capillary forces was presented. The mechanism was demonstrated in an experimental study that used sand packs of varying permeabilities wet-packed into cores with overburden pressures. A fixed injection rate was used to investigate waterflooding in the different permeability systems with 2 different oils. Overall recovery rates were examined as a function of injection velocity. An analysis of normalized oil production rates demonstrated that viscous forces are more important during the early phases of waterflooding. The study showed that breakthrough oil recovery values increased with higher permeability values. However, when injection rates were reduced to low frontal velocity values, the correlation between sand permeability and breakthrough oil recovery resulted in low permeability rates. Lower permeability porous media resulted in more restrictive flow conditions. However, the capillary force components increased as a result of the smaller pore sizes, which in turn led to enhanced water imbibition and higher oil recovery values after water breakthrough. It was concluded that waterflooding rates can be modified later in the recovery process in order to improve final oil recovery values. 21 refs., 3 tabs., 11 figs.

  14. An experimental study of relative permeability hysteresis, capillary trapping characteristics, and capillary pressure of CO2/brine systems at reservoir conditions

    Science.gov (United States)

    Akbarabadi, Morteza

    We present the results of an extensive experimental study on the effects of hysteresis on permanent capillary trapping and relative permeability of CO2/brine and supercritical (sc)CO2+SO2/brine systems. We performed numerous unsteady- and steady-state drainage and imbibition full-recirculation flow experiments in three different sandstone rock samples, i.e., low and high-permeability Berea, Nugget sandstones, and Madison limestone carbonate rock sample. A state-of-the-art reservoir conditions core-flooding system was used to perform the tests. The core-flooding apparatus included a medical CT scanner to measure in-situ saturations. The scanner was rotated to the horizontal orientation allowing flow tests through vertically-placed core samples with about 3.8 cm diameter and 15 cm length. Both scCO2 /brine and gaseous CO2 (gCO2)/brine fluid systems were studied. The gaseous and supercritical CO2/brine experiments were carried out at 3.46 and 11 MPa back pressures and 20 and 55°C temperatures, respectively. Under the above-mentioned conditions, the gCO2 and scCO2 have 0.081 and 0.393 gr/cm3 densities, respectively. During unsteady-state tests, the samples were first saturated with brine and then flooded with CO2 (drainage) at different maximum flow rates. The drainage process was then followed by a low flow rate (0.375 cm 3/min) imbibition until residual CO2 saturation was achieved. Wide flow rate ranges of 0.25 to 20 cm3/min for scCO2 and 0.125 to 120 cm3min for gCO2 were used to investigate the variation of initial brine saturation (Swi) with maximum CO2 flow rate and variation of trapped CO2 saturation (SCO2r) with Swi. For a given Swi, the trapped scCO2 saturation was less than that of gCO2 in the same sample. This was attributed to brine being less wetting in the presence of scCO2 than in the presence of gCO 2. During the steady-state experiments, after providing of fully-brine saturated core, scCO2 was injected along with brine to find the drainage curve and as

  15. Aerobic microbial enhanced oil recovery

    Energy Technology Data Exchange (ETDEWEB)

    Torsvik, T. [Univ. of Bergen (Norway); Gilje, E.; Sunde, E.

    1995-12-31

    In aerobic MEOR, the ability of oil-degrading bacteria to mobilize oil is used to increase oil recovery. In this process, oxygen and mineral nutrients are injected into the oil reservoir in order to stimulate growth of aerobic oil-degrading bacteria in the reservoir. Experiments carried out in a model sandstone with stock tank oil and bacteria isolated from offshore wells showed that residual oil saturation was lowered from 27% to 3%. The process was time dependent, not pore volume dependent. During MEOR flooding, the relative permeability of water was lowered. Oxygen and active bacteria were needed for the process to take place. Maximum efficiency was reached at low oxygen concentrations, approximately 1 mg O{sub 2}/liter.

  16. Effects of Irrigating with Treated Oil and Gas Product Water on Crop Biomass and Soil Permeability

    Energy Technology Data Exchange (ETDEWEB)

    Terry Brown; Jeffrey Morris; Patrick Richards; Joel Mason

    2010-09-30

    Demonstrating effective treatment technologies and beneficial uses for oil and gas produced water is essential for producers who must meet environmental standards and deal with high costs associated with produced water management. Proven, effective produced-water treatment technologies coupled with comprehensive data regarding blending ratios for productive long-term irrigation will improve the state-of-knowledge surrounding produced-water management. Effective produced-water management scenarios such as cost-effective treatment and irrigation will discourage discharge practices that result in legal battles between stakeholder entities. The goal of this work is to determine the optimal blending ratio required for irrigating crops with CBNG and conventional oil and gas produced water treated by ion exchange (IX), reverse osmosis (RO), or electro-dialysis reversal (EDR) in order to maintain the long term physical integrity of soils and to achieve normal crop production. The soils treated with CBNG produced water were characterized with significantly lower SAR values compared to those impacted with conventional oil and gas produced water. The CBNG produced water treated with RO at the 100% treatment level was significantly different from the untreated produced water, while the 25%, 50% and 75% water treatment levels were not significantly different from the untreated water. Conventional oil and gas produced water treated with EDR and RO showed comparable SAR results for the water treatment technologies. There was no significant difference between the 100% treated produced water and the control (river water). The EDR water treatment resulted with differences at each level of treatment, which were similar to RO treated conventional oil and gas water. The 100% treated water had SAR values significantly lower than the 75% and 50% treatments, which were similar (not significantly different). The results of the greenhouse irrigation study found the differences in biomass

  17. Determination of the vertical distribution and areal of the composition in volatile oil and/or gas condensate reservoirs

    International Nuclear Information System (INIS)

    Santos Santos, Nicolas; Ortiz Cancino, Olga Patricia; Barrios Ortiz, Wilson

    2005-01-01

    The compositional variation in vertical and areal direction due to gravitational and thermal effects plays an important role in the determination of the original reserves in-situ and in the selection of the operation scheme for volatile oil and/or gas condensate reservoirs. In this work we presented the mathematical formulation of the thermodynamic behavior experienced by compositional fluids, such as volatile oil and/or gas condensate, under the influence of the mentioned effects (gravitational and thermal), which was implemented in a software tool, this tool determine the compositional variation in vertical direction and, in addition, it allows to know the saturation pressure variation in the hydrocarbon column and the location of the gas-oil contact. With the obtained results, product of the use of this tool, was developed a methodology to obtain one first approach of the compositional variation in areal direction to obtain compositional spatial distribution (iso composition maps) in the reservoir, for components like the methane, which experiences the greater variations. These iso composition maps allow to determine the location of the hydrocarbon deposits, in such a way that the production strategies can be selected and be applied to maximize the recovery, such as in fill wells, perforation of new zones, EOR processes, etc

  18. Reviving Abandoned Reservoirs with High-Pressure Air Injection: Application in a Fractured and Karsted Dolomite Reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Robert Loucks; Stephen C. Ruppel; Dembla Dhiraj; Julia Gale; Jon Holder; Jeff Kane; Jon Olson; John A. Jackson; Katherine G. Jackson

    2006-09-30

    Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. The successful development of HPAI technology has tremendous potential for increasing the flow of oil from deep carbonate reservoirs in the Permian Basin, a target resource that can be conservatively estimated at more than 1.5 billion barrels. Successful implementation in the field chosen for demonstration, for example, could result in the recovery of more than 34 million barrels of oil that will not otherwise be produced. Geological and petrophysical analysis of available data at Barnhart field reveals the following important observations: (1) the Barnhart Ellenburger reservoir is similar to most other Ellenburger reservoirs in terms of depositional facies, diagenesis, and petrophysical attributes; (2) the reservoir is characterized by low to moderate matrix porosity much like most other Ellenburger reservoirs in the Permian Basin; (3) karst processes (cave formation, infill, and collapse) have substantially altered stratigraphic architecture and reservoir properties; (4) porosity and permeability increase with depth and may be associated with the degree of karst-related diagenesis; (5) tectonic fractures overprint the reservoir, improving overall connectivity; (6) oil-saturation profiles show that the oil-water contact (OWC) is as much as 125 ft lower than previous estimations; (7) production history and trends suggest that this reservoir is very similar to other solution-gas-drive reservoirs in the Permian Basin; and (8) reservoir simulation study showed that the Barnhart reservoir is a good candidate for HPAI and that application of horizontal-well technology can improve ultimate resource recovery from the reservoir.

  19. MAPPING OF RESERVOIR PROPERTIES AND FACIES THROUGH INTEGRATION OF STATIC AND DYNAMIC DATA

    Energy Technology Data Exchange (ETDEWEB)

    Albert C. Reynolds; Dean S. Oliver; Yannong Dong; Ning Liu; Guohua Gao; Fengjun Zhang; Ruijian Li

    2004-12-01

    Knowledge of the distribution of permeability and porosity in a reservoir is necessary for the prediction of future oil production, estimation of the location of bypassed oil, and optimization of reservoir management. The volume of data that can potentially provide information on reservoir architecture and fluid distributions has increased enormously in the past decade. The techniques developed in this research will make it easier to use all the available data in an integrated fashion. While it is relatively easy to generate plausible reservoir models that honor static data such as core, log, and seismic data, it is far more difficult to generate plausible reservoir models that honor dynamic data such as transient pressures, saturations, and flow rates. As a result, the uncertainty in reservoir properties is higher than it could be and reservoir management can not be optimized. In this project, we have developed computationally efficient automatic history matching techniques for generating geologically plausible reservoir models which honor both static and dynamic data. Specifically, we have developed methods for adjusting porosity and permeability fields to match both production and time-lapse seismic data and have also developed a procedure to adjust the locations of boundaries between facies to match production data. In all cases, the history matched rock property fields are consistent with a prior model based on static data and geologic information. Our work also indicates that it is possible to adjust relative permeability curves when history matching production data.

  20. Evaluation of Reservoir Wettability and its Effect on Oil Recovery; FINAL

    International Nuclear Information System (INIS)

    Buckley, Jill S.

    2002-01-01

    The objectives of this five-year project were: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding

  1. Pore network modelling of heavy oil depressurization : a parametric study of factors affecting critical gas saturation and three-phase relative permeabilities

    Energy Technology Data Exchange (ETDEWEB)

    Bondino, I.; McDougall, S.D. [Heriot-Watt Univ., Edinburgh, Scotland (United Kingdom); Hamon, G. [TotalFina Elf Exploration and Production (France)

    2002-07-01

    A review of how the bubble nucleation process affects the efficiency of heavy oil recovery was presented along with a discussion regarding a pore-scale simulator technique to depressurize heavy oil systems. A light oil depressurization simulation is also presented in which a straightforward instantaneous nucleation (IN) model and a more intricate progressive nucleation (PN) model have been used. Simulation results are compared to those derived from the heavy oil systems. The nucleation of bubbles, their growth by solute diffusion and expansion, plus the final stages of coalescence migration and production are the main steps in the depressurization process which were accounted for in a 3-phase simulator. The model can also determine the impact of bubble density and gas-oil diffusion coefficient on critical gas saturation and 3-phase relative permeability. The difference in results for light and heavy oils was also highlighted. In the first scenario, the evolution of gas was characterized by embryonic bubbles that are quickly and randomly nucleated once bubble-point pressure is reached. A stochastic algorithm was developed for PN from experimental observations. IN and PN observations were not necessarily contradictory. It was determined that the high interfacial tension of heavy oils leads to a more compact, capillary-dominated pattern of gas evolution compared to light oils, resulting in improved recoveries for heavy oil systems. 23 refs., 6 tabs., 23 figs.

  2. Play Analysis and Digital Portfolio of Major Oil Reservoirs in the Permian Basin: Application and Transfer of Advanced Geological and Engineering Technologies for Incremental Production Opportunities

    Energy Technology Data Exchange (ETDEWEB)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

    2004-01-13

    A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest onshore petroleum-producing basin in the United States. Approximately 1,300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of oil through 2000. Of these significant-sized reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. There are 32 geologic plays that have been defined for Permian Basin oil reservoirs, and each of the 1,300 major reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. The final reservoir shapefile for each play contains the geographic location of each reservoir. Associated reservoir information within the linked data tables includes RRC reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are smaller than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. Oil production from the reservoirs in the Permian Basin having cumulative production of >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl [5.25 x 10{sup 8} m{sup 3}]), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres Platform Carbonate play (2.15 Bbbl [3.42 x 10{sup 8} m{sup 3}]). Detailed studies of three reservoirs

  3. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    International Nuclear Information System (INIS)

    Chidsey Jr., Thomas C.

    2003-01-01

    The primary objective of this project was to enhance domestic petroleum production by field demonstration and technology transfer of an advanced-oil-recovery technology in the Paradox Basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox Basin alone, and result in increased recovery of 150 to 200 million barrels (23,850,000-31,800,000 m3) of oil. This project was designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon-dioxide-(CO2-) miscible flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place within the Navajo Nation, San Juan County, Utah

  4. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah; ANNUAL

    International Nuclear Information System (INIS)

    Jr., Chidsey, Thomas C.; Allison, M. Lee

    1999-01-01

    The primary objective of this project is to enhance domestic petroleum production by field demonstration and technology transfer of an advanced- oil-recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels (23,850,000-31,800,000 m3) of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon-dioxide-(CO2-) miscible flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place within the Navajo Nation, San Juan County, Utah

  5. Dynamics of waterflooding massive oil deposits in the Chechen Ingush ASSR, including fissured reservoirs in the late stages of development

    Energy Technology Data Exchange (ETDEWEB)

    Tatashev, K.Kh.; Soboleva, G.N.; Tagunova, A.V.

    1979-01-01

    In 1956 in the Chechen Ingush ASSR a number of massive oil deposits located in fissured cavernous Upper Cretaceous limestone were developed. The deposits were developed by water-oil displacement from the edges and pericline toward the dome of the structure using the natural water pressure drive as well as artificial marginal flooding. The great oil-bearing capacity, the good hydrodynamic link with the deposit, the close magnitude of oil viscosity and water under the layer conditions and the significant difference in their density (0.4-0.5 g/cm/sup 3/) practically guarantees pistonlike oil displacement. Based on the deposit's geologic-physical characteristics, the late stage of development may be characterized by noncontinuous time and a sharp increase in well waterflooding to maintain full flooding. However, the data obtained from working the field suggest that a sharp increase in waterflooding will be substituted by a slow increase, by stabilization and possibly even a decrease in the percentage of water over the last 3-6 years. This occurred in a number of cases where measures were taken to limit the liquid flow, to periodically operate the well with isolated waterflooding and pereclinal perforation at intervals. This also occurred in a number of cases where the rate of fluid yield was naturally lowered by decreasing the number of producing wells due to waterflooding and disengagement. To more completely extract the oil from relatively low permeable areas of the deposits and to develop them in the later stages, it is useful to use a slow tempo once all wells have been brought to perclinal interval operation.

  6. Different Diversity and Distribution of Archaeal Community in the Aqueous and Oil Phases of Production Fluid From High-Temperature Petroleum Reservoirs

    Directory of Open Access Journals (Sweden)

    Bo Liang

    2018-04-01

    Full Text Available To get a better knowledge on how archaeal communities differ between the oil and aqueous phases and whether environmental factors promote substantial differences on microbial distributions among production wells, we analyzed archaeal communities in oil and aqueous phases from four high-temperature petroleum reservoirs (55–65°C by using 16S rRNA gene based 454 pyrosequencing. Obvious dissimilarity of the archaeal composition between aqueous and oil phases in each independent production wells was observed, especially in production wells with higher water cut, and diversity in the oil phase was much higher than that in the corresponding aqueous phase. Statistical analysis further showed that archaeal communities in oil phases from different petroleum reservoirs tended to be more similar, but those in aqueous phases were the opposite. In the high-temperature ecosystems, temperature as an environmental factor could have significantly affected archaeal distribution, and archaeal diversity raised with the increase of temperature (p < 0.05. Our results suggest that to get a comprehensive understanding of petroleum reservoirs microbial information both in aqueous and oil phases should be taken into consideration. The microscopic habitats of oil phase, technically the dispersed minuscule water droplets in the oil could be a better habitat that containing the indigenous microorganisms.

  7. Characteristics of volcanic reservoirs and distribution rules of effective reservoirs in the Changling fault depression, Songliao Basin

    Directory of Open Access Journals (Sweden)

    Pujun Wang

    2015-11-01

    Full Text Available In the Songliao Basin, volcanic oil and gas reservoirs are important exploration domains. Based on drilling, logging, and 3D seismic (1495 km2 data, 546 sets of measured physical properties and gas testing productivity of 66 wells in the Changling fault depression, Songliao Basin, eruptive cycles and sub-lithofacies were distinguished after lithologic correction of the 19,384 m volcanic well intervals, so that a quantitative analysis was conducted on the relation between the eruptive cycles, lithologies and lithofacies and the distribution of effective reservoirs. After the relationship was established between lithologies, lithofacies & cycles and reservoir physical properties & oil and gas bearing situations, an analysis was conducted on the characteristics of volcanic reservoirs and the distribution rules of effective reservoirs. It is indicated that 10 eruptive cycles of 3 sections are totally developed in this area, and the effective reservoirs are mainly distributed at the top cycles of eruptive sequences, with those of the 1st and 3rd Members of Yingcheng Formation presenting the best reservoir properties. In this area, there are mainly 11 types of volcanic rocks, among which rhyolite, rhyolitic tuff, rhyolitic tuffo lava and rhyolitic volcanic breccia are the dominant lithologies of effective reservoirs. In the target area are mainly developed 4 volcanic lithofacies (11 sub-lithofacies, among which upper sub-lithofacies of effusive facies and thermal clastic sub-lithofacies of explosion lithofacies are predominant in effective reservoirs. There is an obvious corresponding relationship between the physical properties of volcanic reservoirs and the development degree of effective reservoirs. The distribution of effective reservoirs is controlled by reservoir physical properties, and the formation of effective reservoirs is influenced more by porosity than by permeability. It is concluded that deep volcanic gas exploration presents a good

  8. The role of nitrogen and sulphur bearing compounds in the wettability of oil reservoir rocks: an approach with nuclear microanalysis and other related surface techniques

    International Nuclear Information System (INIS)

    Mercier, F.; Toulhoat, N.; Potocek, V.; Trocellier, P.

    1999-01-01

    Oil recovery is strongly influenced by the wettability of the reservoir rock. Some constituents of the crude oil (polar compounds and heavy fractions such as asphaltenes with heteroatoms) are believed to react with the reservoir rock and to condition the local wettability. Therefore, it is important to obtain as much knowledge as possible about the characteristics of the organic matter/mineral interactions. This study is devoted to the description at the microscopic scale of the distribution of some heavy fractions of crude oil (asphaltenes) and nitrogen molecules (pyridine and pyrrole) on model minerals of sandstone reservoir rocks such as silica and clays. Nuclear microanalysis, X-Ray Photoelectron Spectroscopy and other related microscopic imaging techniques allow to study the distribution and thickness of the organic films. The respective influences of the nature of the mineral substrate and the organic matter are studied. The important role played by the nitrogen compounds in the adsorption of organic matter is emphasized

  9. Using combinations of methods for evaluating capacity of fissured reservoirs of the upper Cretaceous Malgobek- Voznesensk oil deposit in Ch. I. ASSR

    Energy Technology Data Exchange (ETDEWEB)

    Vasilev, V.M.

    1968-01-01

    Ch.I.ASSR stands for the Chechen-Ingush Autonomous Soviet Socialist Republic (North Caucasus). The deposit is associated with practically impervious limestones (less than 1 md) with intergranular porosity; oil is found along fractures of various length and degree of openness. Amount of fluids contained in this type of reservoirs was evaluated by the following methods: (1) core analyses; (2) geophysical surveying of wells; (3) hydrodynamic techniques of well investigations; and (4) according to parts of the deposits where oil was already recovered. Statistical interpretation of combined data indicated that reservoir properties gradually become poorer with increasing depth and in the direction from the crest of the fold towards its flanks and periclinal ends. Application of some formulas used in this work is explained. It is concluded that by using combinations of methods it is possible to evaluate the absolute and effective values of secondary reservoir capacity and to establish approximately geological and retrievable oil reserves.

  10. An experimental study of tracers for labelling of injection gas in oil reservoirs

    International Nuclear Information System (INIS)

    Dugstad, Oe.

    1992-01-01

    This work demonstrates the feasibility of the PMCP and PMCH as tracers in field experiments. These compounds have properties which make them as well suited for well to well studies as the more common tracers CH 3 T and 85 Kr. In an injection project carried out at the Gullfaks field in the North Sea the two PFCs verified communication between wells. This implies communication between different geological layers in the reservoir and also communication across faults within the same layers. Laboratory studies carried out have focused on the retention of the tracers in dynamic flooding experiments under conditions comparable with those in the petroleum reservoirs. Simultaneous injection of a variety of tracers has shown individual variations in tracer retention which are caused by important reservoir parameters as fluid saturation and rock properties. By proper design of field injection programs the tracers response may therefore be used to estimate fluid saturation if actual rock properties are known. 45 refs., 20 figs., 13 tabs

  11. Use of black oil simulator for coal bed methane reservoir model

    Energy Technology Data Exchange (ETDEWEB)

    Sonwa, R.; Enachescu, C.; Rohs, S. [Golder Associates GmbH, Celle (Germany)

    2013-08-01

    This paper starts from the work done by Seidle et al. (1990) and other authors on the topic of coal degasification and develops a more accurate representative naturally fractured CBM-reservoir by using a Discrete Fracture Network modeling approach. For this issue we firstly calibrate the reservoir simulator tNAVIGATOR by showing his ability to reproduce the work done by Seidle et al. and secondly generate a DFN model using FracMan in accordance with the distribution and orientation of the cleats. tNavigator was then used to simulate multiphase flow through the DFN- Model. (orig.)

  12. PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

    Energy Technology Data Exchange (ETDEWEB)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; William Raatz; Cari Breton; Stephen C. Ruppel; Charles Kerans; Mark H. Holtz

    2003-04-01

    A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest petroleum-producing basin in the US. Approximately 1300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl of oil through 2000. Of these major reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. On a preliminary basis, 32 geologic plays have been defined for Permian Basin oil reservoirs and assignment of each of the 1300 major reservoirs to a play has begun. The reservoirs are being mapped and compiled in a Geographic Information System (GIS) by play. Detailed studies of three reservoirs are in progress: Kelly-Snyder (SACROC unit) in the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play, Fullerton in the Leonardian Restricted Platform Carbonate play, and Barnhart (Ellenburger) in the Ellenburger Selectively Dolomitized Ramp Carbonate play. For each of these detailed reservoir studies, technologies for further, economically viable exploitation are being investigated.

  13. PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

    Energy Technology Data Exchange (ETDEWEB)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

    2004-05-01

    The Permian Basin of west Texas and southeast New Mexico has produced >30 Bbbl (4.77 x 10{sup 9} m{sup 3}) of oil through 2000, most of it from 1,339 reservoirs having individual cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}). These significant-sized reservoirs are the focus of this report. Thirty-two Permian Basin oil plays were defined, and each of the 1,339 significant-sized reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. Associated reservoir information within linked data tables includes Railroad Commission of Texas reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are <1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. This report contains a summary description of each play, including key reservoir characteristics and successful reservoir-management practices that have been used in the play. The CD accompanying the report contains a pdf version of the report, the GIS project, pdf maps of all plays, and digital data files. Oil production from the reservoirs in the Permian Basin having cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 from these significant-sized reservoirs was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl 5.25 x 10{sup 8} m{sup 3}), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres

  14. A Combined Thermodynamic and Kinetic Model for Barite Prediction at Oil Reservoir Conditions

    DEFF Research Database (Denmark)

    Zhen Wu, Bi Yun

    of the literature (PhD Study 1). The reviewed dataset was used as starting point for geochemical speciation modelling and applied to predict the stability of sulphate minerals in North Sea oil field brines. Second, for modelling of high salinity solutions using the Pitzer ion interaction approach, the temperature...... observations. This information can help planning mitigation and optimise costs in oil production....

  15. Single Shooting and ESDIRK Methods for adjoint-based optimization of an oil reservoir

    DEFF Research Database (Denmark)

    Capolei, Andrea; Völcker, Carsten; Frydendall, Jan

    2012-01-01

    the injections and oil production such that ow is uniform in a given geological structure. Even in the case of conventional water ooding, feedback based optimal control technologies may enable higher oil recovery than with conventional operational strategies. The optimal control problems that must be solved...

  16. Analysis of Microbial Communities in the Oil Reservoir Subjected to CO2-Flooding by Using Functional Genes as Molecular Biomarkers for Microbial CO2 Sequestration

    Directory of Open Access Journals (Sweden)

    Jin-Feng eLiu

    2015-03-01

    Full Text Available Sequestration of CO2 in oil reservoirs is considered to be one of the feasible options for mitigating atmospheric CO2 building up and also for the in situ potential bioconversion of stored CO2 to methane. However, the information on these functional microbial communities and the impact of CO2 storage on them is hardly available. In this paper a comprehensive molecular survey was performed on microbial communities in production water samples from oil reservoirs experienced CO2-flooding by analysis of functional genes involved in the process, including cbbM, cbbL, fthfs, [FeFe]-hydrogenase and mcrA. As a comparison, these functional genes in the production water samples from oil reservoir only experienced water-flooding in areas of the same oil bearing bed were also analyzed. It showed that these functional genes were all of rich diversity in these samples, and the functional microbial communities and their diversity were strongly affected by a long-term exposure to injected CO2. More interestingly, microorganisms affiliated with members of the genera Methanothemobacter, Acetobacterium and Halothiobacillus as well as hydrogen producers in CO2 injected area either increased or remained unchanged in relative abundance compared to that in water-flooded area, which implied that these microorganisms could adapt to CO2 injection and, if so, demonstrated the potential for microbial fixation and conversion of CO2 into methane in subsurface oil reservoirs.

  17. Shampooing the reservoir : organic surfactant could increase Suffield oil recovery by 10 per cent

    Energy Technology Data Exchange (ETDEWEB)

    Roche, P.

    2009-10-15

    EnCana is testing a new tertiary recovery technology in the Suffield area of southeastern Alberta which is known primarily for shallow natural gas. EnCana Corporation has approximately 1 billion barrels of original heavy oil in place in the Suffield area. Oil densities range from about 10 to 18 degrees API gravity. Viscosities range from 100 to 10,000 centipoise. Drilling began about 30 years ago. The primary productive formation is consolidated Mannville Glauconite sandstone which produces very little sand with the oil. About 15 per cent of the oil in place has been produced by primary production and waterfloods. In 2007, EnCana began testing an alkaline surfactant polymer flood operation in the Suffield heavy oil field that consists of 2 injector wells and 5 producers. Tests will continue until 2011. The surfactant acts as a detergent and reduces the interfacial tension between water and oil, thus mobilizing residual oil and increasing the displacement efficiency. In addition to the physical sweeping of a straight polymer flood, a surfactant polymer also washes oil from the rock. EnCana buys an alkaline chemical that is less expensive than surfactant. The alkaline injectant reacts with the organic acids in the oil to create a natural surfactant. EnCana was granted experimental scheme status by the Alberta Energy Resources Conservation Board. Instead of using fresh water, the pilot mixes its chemicals with saline water from a deep formation. EnCana will consider the pilot a commercial success if it recovers at least 10 per cent of the original oil in place. Thus far, the pilot is meeting that threshold. 1 fig.

  18. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Second annual report, October 1993--September 1994

    Energy Technology Data Exchange (ETDEWEB)

    Pitts, M.J.

    1995-04-01

    {open_quotes}Investigation of Oil Recovery Improvement by Coupling an Interfacial Tension Agent and a Mobility Control Agent in Light Oil Reservoirs{close_quotes} is studying two major areas concerning co-injecting an interfacial tension reduction agent(s) and a mobility control agent. The first area defines the interactions of alkaline agents, surfactants, and polymers on a fluid-fluid and a fluid-rock basis. The second area concerns the economic improvement of the combined technology. This report continues the fluid-fluid interaction evaluations and begins the fluid-rock studies. Fluid-fluid interfacial tension work determined that replacing sodium ion with either potassium or ammonium ion in solutions with interfacial tension reduction up to 19,600 fold was detrimental and had little or no effect on alkali-surfactant solutions with interfacial tension reduction of 100 to 200 fold. Reservoir brine increases interfacial tension between crude oil and alkaline-surfactant solutions. Na{sub 2}CO{sub 3}-surfactant solutions maintained ultra low and low interfacial tension values better than NaOH-surfactant solutions. The initial phase of the fluid-rock investigations was adsorption studies. Surfactant adsorption is reduced when co-dissolved with alkali. Na{sub 2}CO{sub 3} and Na{sub 3}PO{sub 4} are more efficient at reducing surfactant adsorption than NaOH. When polymer is added to the surfactant solution, surfactant adsorption is reduced as well. When both polymer and alkali are added, polymer is the dominate component, reducing the Na{sub 2}CO{sub 3} and NaOH effect on adsorption. Substituting sodium ion with potassium or ammonium ion increased or decreased surfactant adsorption depending on surfactant structure with alkali having a less significant effect. No consistent change of surfactant adsorption with increasing salinity was observed in the presence or absence of alkali or polymer.

  19. Improved recovery from Gulf of Mexico reservoirs. Quarterly status report, January 1--March 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Kimbrell, W.C.; Bassiouni, Z.A.; Bourgoyne, A.T.

    1996-04-30

    On February 18, 1992, Louisiana State University with two technical subcontractors, BDM, Inc. and ICF, Inc., began a research program to estimate the potential oil and gas reserve additions that could result from the application of advanced secondary and enhanced oil recovery technologies and the exploitation of undeveloped and attic oil zones in the Gulf of Mexico oil fields that are related to piercement salt domes. This project is a one year continuation of this research and will continue work in reservoir description, extraction processes, and technology transfer. Detailed data will be collected for two previously studies reservoirs: a South Marsh Island reservoir operated by Taylor Energy and one additional Gulf of Mexico reservoir operated by Mobil. Additional reservoirs identified during the project will also be studied if possible. Data collected will include reprocessed 2-D seismic data, newly acquired 3-D data, fluid data, fluid samples, pressure data, well test data, well logs, and core data/samples. The new data will be used to refine reservoir and geologic characterization of these reservoirs. Further laboratory investigation will provide additional simulation input data in the form of PVT properties, relative permeabilities, capillary pressure, and water compatibility. Geological investigations will be conducted to refine the models of mud-rich submarine fan architectures used by seismic analysts and reservoir engineers. Research on advanced reservoir simulation will also be conducted. This report describes a review of fine-grained submarine fans and turbidite systems.

  20. Visual display of reservoir parameters affecting enhanced oil recovery. Final report, September 29, 1993--September 28, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Wood, J.R.

    1997-05-01

    The Pioneer Anticline, 25 miles southwest of Bakersfield, California, which has yielded oil since 1926, was the subject of a three-year study aimed at recovering more oil. A team from Michigan Technological University of Houghton, Michigan (MTU), and Digital Petrophysics, Inc. of Bakersfield, California (DPI), undertook the study as part of the Department of Energy`s Advanced Extraction and Process Technology Program. The program provides support for projects which cross-cut geoscience and engineering research in order to develop innovative technologies for increasing the recovery of some of the estimated 340 billion barrels of in-place oil remaining in U.S. reservoirs. In recent years, low prices and declining production have increased the likelihood that oil fields will be prematurely abandoned, locking away large volumes of unrecovered oil. The major companies have sold many of their fields to smaller operators in an attempt to concentrate their efforts on fewer {open_quotes}core{close_quotes} properties and on overseas exploration. As a result, small companies with fewer resources at their disposal are becoming responsible for an ever-increasing share of U.S. production. The goal of the MTU-DPI project was to make small independent producers who are inheriting old fields from the majors aware that high technology computer software is now available at relatively low cost. In this project, a suite of relatively inexpensive, PC-based software packages, including a commercial database, a multimedia presentation manager, several well-log analysis program, a mapping and cross-section program, and 2-D and 3-D visualization programs, were tested and evaluated on Pioneer Anticline in the southern San Joaquin Valley of California. These relatively inexpensive, commercially available PC-based programs can be assembled into a compatible package for a fraction of the cost of a workstation program with similar capabilities.

  1. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman R. Morrow

    2004-05-01

    We report on progress in three areas. In part one, the wetting effects of synthetic base oils are reported. Part two reports progress in understanding the effects of surfactants of known chemical structures, and part three integrates the results from surface and core tests that show the wetting effects of commercial surfactant products used in synthetic and traditional oil-based drilling fluids. An important difference between synthetic and traditional oil-based muds (SBM and OBM, respectively) is the elimination of aromatics from the base oil to meet environmental regulations. The base oils used include dearomatized mineral oils, linear alpha-olefins, internal olefins, and esters. We show in part one that all of these materials except the esters can, at sufficiently high concentrations, destabilize asphaltenes. The effects of asphaltenes on wetting are in part related to their stability. Although asphaltenes have some tendency to adsorb on solid surfaces from a good solvent, that tendency can be much increased near the onset of asphaltene instability. Tests in Berea sandstone cores demonstrate wetting alteration toward less water-wet conditions that occurs when a crude oil is displaced by paraffinic and olefinic SBM base oils, whereas exposure to the ester products has little effect on wetting properties of the cores. Microscopic observations with atomic forces microscopy (AFM) and macroscopic contact angle measurements have been used in part 2 to explore the effects on wetting of mica surfaces using oil-soluble polyethoxylated amine surfactants with varying hydrocarbon chain lengths and extent of ethoxylation. In the absence of water, only weak adsorption occurs. Much stronger, pH-dependent adsorption was observed when water was present. Varying hydrocarbon chain length had little or no effect on adsorption, whereas varying extent of ethoxylation had a much more significant impact, reducing contact angles at nearly all conditions tested. Preequilibration of

  2. Evaluating the Influence of Pore Architecture and Initial Saturation on Wettability and Relative Permeability in Heterogeneous, Shallow-Shelf Carbonates

    Energy Technology Data Exchange (ETDEWEB)

    Byrnes, Alan P.; Bhattacharya, Saibal; Victorine, John; Stalder, Ken

    2007-09-30

    Thin (3-40 ft thick), heterogeneous, limestone and dolomite reservoirs, deposited in shallow-shelf environments, represent a significant fraction of the reservoirs in the U.S. midcontinent and worldwide. In Kansas, reservoirs of the Arbuckle, Mississippian, and Lansing-Kansas City formations account for over 73% of the 6.3 BBO cumulative oil produced over the last century. For these reservoirs basic petrophysical properties (e.g., porosity, absolute permeability, capillary pressure, residual oil saturation to waterflood, resistivity, and relative permeability) vary significantly horizontally, vertically, and with scale of measurement. Many of these reservoirs produce from structures of less than 30-60 ft, and being located in the capillary pressure transition zone, exhibit vertically variable initial saturations and relative permeability properties. Rather than being simpler to model because of their small size, these reservoirs challenge characterization and simulation methodology and illustrate issues that are less apparent in larger reservoirs where transition zone effects are minor and most of the reservoir is at saturations near S{sub wirr}. These issues are further augmented by the presence of variable moldic porosity and possible intermediate to mixed wettability and the influence of these on capillary pressure and relative permeability. Understanding how capillary-pressure properties change with rock lithology and, in turn, within transition zones, and how relative permeability and residual oil saturation to waterflood change through the transition zone is critical to successful reservoir management and as advanced waterflood and improved and enhanced recovery methods are planned and implemented. Major aspects of the proposed study involve a series of tasks to measure data to reveal the nature of how wettability and drainage and imbibition oil-water relative permeability change with pore architecture and initial water saturation. Focus is placed on

  3. Determination of oil reservoir radiotracer (S14CN−) in a single step using a plastic scintillator extractive resin

    International Nuclear Information System (INIS)

    Bagán, H.; Tarancón, A.; Stavsetra, L.; Rauret, G.; García, J.F.

    2012-01-01

    Highlights: ► A new procedure for S 14 CN − radiotracer determination using PS resin was established. ► The minimum detectable activity for a 100 mL sample is 0.08 Bq L −1 . ► The minimum quantifiable activity for a 100 mL sample is 0.31 Bq L −1 . ► PS resin is capable to quantify S 14 CN − radiotracer samples with errors lower than 5%. ► PS resin is also capable to quantify complex matrices obtained from oil reservoirs. - Abstract: The analysis of radiotracers is important in the study of oil reservoir dynamics. One of the most widely used radiotracer is S 14 CN − . Prior to activity measurements by Liquid Scintillation (LS), routine determinations require the pretreatment steps of purification and concentration of the samples using anion exchange columns. The final elution media produces samples with high salt concentration that may lead to problems with phase separation during the LS measurement. Plastic Scintillation (PS) is an alternative technique that provides a solid surface that can be used as a platform for the immobilisation of selective extractants to obtain a PS resin. The proposed procedure unifies chemical separation and sample measurement preparation in a single step, serving to reduce the number of reagents needed and manpower required for the analysis while also avoiding mixed waste production by LS. The objective of this study is to develop a PS resin for the determination of 14 C-labelled thiocyanate radiotracer in water samples. For this purpose, the immobilisation procedure was optimised, including optimisation of the proportion of PS microspheres:extractant and the use of a control blank to monitor the PS resin immobilisation process. The breakthrough volume was studied and the detection and quantification limits for 100 mL of sample were determined to be 0.08 Bq L −1 and 0.31 Bq L −1 , respectively. The established procedure was applied to active samples from oil reservoirs and errors lower than 5% in the sample

  4. Theoretical and experimental fundamentals of designing promising technological equipment to improve efficiency and environmental safety of highly viscous oil recovery from deep oil reservoirs

    Science.gov (United States)

    Moiseyev, V. A.; Nazarov, V. P.; Zhuravlev, V. Y.; Zhuykov, D. A.; Kubrikov, M. V.; Klokotov, Y. N.

    2016-12-01

    The development of new technological equipment for the implementation of highly effective methods of recovering highly viscous oil from deep reservoirs is an important scientific and technical challenge. Thermal recovery methods are promising approaches to solving the problem. It is necessary to carry out theoretical and experimental research aimed at developing oil-well tubing (OWT) with composite heatinsulating coatings on the basis of basalt and glass fibers. We used the method of finite element analysis in Nastran software, which implements complex scientific and engineering calculations, including the calculation of the stress-strain state of mechanical systems, the solution of problems of heat transfer, the study of nonlinear static, the dynamic transient analysis of frequency characteristics, etc. As a result, we obtained a mathematical model of thermal conductivity which describes the steady-state temperature and changes in the fibrous highly porous material with the heat loss by Stefan-Boltzmann's radiation. It has been performed for the first time using the method of computer modeling in Nastran software environments. The results give grounds for further implementation of the real design of the OWT when implementing thermal methods for increasing the rates of oil production and mitigating environmental impacts.

  5. Wettability Improvement with Enzymes: Application to Enhanced Oil Recovery under Conditions of the North Sea Reservoirs

    DEFF Research Database (Denmark)

    Khusainova, Alsu; Shapiro, Alexander; Stenby, Erling Halfdan

    2012-01-01

    (Nasiri et al., 2009), working mechanisms are poorly known and understood. The main goal of the present work is to establish possible mechanisms in which enzymes may enhance oil recovery. Improvement of the brine wettability of the rock and decrease of oil adhesion to it by addition of an enzyme is one...... of the possible mechanisms of enzymatic action. This mechanism has been investigated experimentally, by measurements of the contact angles between oil drops and enzyme solutions in brine on the mineral surfaces. Fifteen enzyme samples belonging to different enzyme classes, such as esterases/lipases, carbohydrases......, proteases and oxidoreductases, provided by Novozymes, have been investigated. Two commercial mixtures containing enzymes: Apollo-GreenZyme™ and EOR-ZYMAX™ have also been applied. The North Sea dead oil and the synthetic sea water were used as test fluids. Internal surface of a carbonate rock has been...

  6. Improved characterization of reservoir behavior by integration of reservoir performances data and rock type distributions

    Energy Technology Data Exchange (ETDEWEB)

    Davies, D.K.; Vessell, R.K. [David K. Davies & Associates, Kingwood, TX (United States); Doublet, L.E. [Texas A& M Univ., College Station, TX (United States)] [and others

    1997-08-01

    An integrated geological/petrophysical and reservoir engineering study was performed for a large, mature waterflood project (>250 wells, {approximately}80% water cut) at the North Robertson (Clear Fork) Unit, Gaines County, Texas. The primary goal of the study was to develop an integrated reservoir description for {open_quotes}targeted{close_quotes} (economic) 10-acre (4-hectare) infill drilling and future recovery operations in a low permeability, carbonate (dolomite) reservoir. Integration of the results from geological/petrophysical studies and reservoir performance analyses provide a rapid and effective method for developing a comprehensive reservoir description. This reservoir description can be used for reservoir flow simulation, performance prediction, infill targeting, waterflood management, and for optimizing well developments (patterns, completions, and stimulations). The following analyses were performed as part of this study: (1) Geological/petrophysical analyses: (core and well log data) - {open_quotes}Rock typing{close_quotes} based on qualitative and quantitative visualization of pore-scale features. Reservoir layering based on {open_quotes}rock typing {close_quotes} and hydraulic flow units. Development of a {open_quotes}core-log{close_quotes} model to estimate permeability using porosity and other properties derived from well logs. The core-log model is based on {open_quotes}rock types.{close_quotes} (2) Engineering analyses: (production and injection history, well tests) Material balance decline type curve analyses to estimate total reservoir volume, formation flow characteristics (flow capacity, skin factor, and fracture half-length), and indications of well/boundary interference. Estimated ultimate recovery analyses to yield movable oil (or injectable water) volumes, as well as indications of well and boundary interference.

  7. Emissions from hydroelectric reservoirs and comparison of hydroelectricity, natural gas and oil

    International Nuclear Information System (INIS)

    Gagnon, L.; Chamberland, A.

    1993-01-01

    When reservoirs are created, a small fraction of the flooded organic matter decomposes into humic acids, carbon dioxide (CO 2 ), methane (CH 4 ), nitrogen, phosphorus, and other elements. The major greenhouse gases produced are CO 2 and CH 4 . For northern projects, Canadian studies on emissions from hydroelectric reservoirs have reached similar conclusions: Emissions, including methane, are less than 35 kg CO 2 equivalent per MWh. Using a typical project in northern Quebec as the basis for analysis, none of the studies dispute the considerable advantages of hydroelectricity regarding greenhouse gas emissions. Taking into account all components of energy systems, emissions of greenhouse gases from natural-gas power plants are 24 to 26 times greater than emissions from hydroelectric plants. The Freshwater Institute, in an article published in Ambio suggests that emissions from hydroelectric plants could be a significant source of greenhouse gases. This conclusion does not apply to most hydroelectric projects for two reasons: First, the Freshwater Institute's studies concerned flooded peatlands and shallow reservoirs that are not typical of most hydro projects; and second, the Institute analyzed a hydro project with a ratio of flooded area to energy production that is 6 to 10 times higher than typical projects in Canada. 7 refs, 4 tabs

  8. SAGD pilot project, wells MFB-772 (producer) / MFB-773 (injector), U1,3 MFB-53 reservoir, Bare Field. Orinoco oil belt. Venezuela

    Energy Technology Data Exchange (ETDEWEB)

    Mago, R.; Franco, L.; Armas, F.; Vasquez, R.; Rodriguez, J.; Gil, E. [PDVSA EandP (Venezuela)

    2011-07-01

    In heavy oil and extra heavy oil fields, steam assisted gravity drainage is a thermal recovery method used to reduce oil viscosity and thus increase oil recovery. For SAGD to be successfully applied in deep reservoirs, drilling and completion of the producer and injector wells are critical. Petroleos de Venezuela SA (PDVSA) is currently assessing the feasibility of SAGD in the Orinoco oil belt in Venezuela and this paper aims at presenting the methodology used to ensure optimal drilling and completion of the project. This method was divided in several stages: planning, drilling and completion of the producer, injector and then of the observer wells and cold information capture. It was found that the use of magnetic guidance tools, injection pipe pre-insulated and pressure and temperature sensors helps optimize the drilling and completion process. A methodology was presented to standardize operational procedures in the drilling and completion of SAGD projects in the Orinoco oil belt.

  9. Influence of Palm Oil Fuel Ash and W/B Ratios on Compressive Strength, Water Permeability, and Chloride Resistance of Concrete

    Directory of Open Access Journals (Sweden)

    Wachilakorn Sanawung

    2017-01-01

    Full Text Available This research studies the effects of W/B ratios and palm oil fuel ash (POFA on compressive strength, water permeability, and chloride resistance of concrete. POFA was ground until the particles retained on sieve number 325 were less than 5% by weight. POFA was used to partially replace OPC at rates of 15, 25, and 35% by weight of binder. The water to binder (W/B ratios of concrete were 0.40 and 0.50. The compressive strength, water permeability, and chloride resistance of concrete were investigated up to 90 days. The results showed that POFA concrete with W/B ratio of 0.40 had the compressive strengths ranging from 45.8 to 55.9 MPa or 82–94% of OPC concrete at 90 days, while POFA concrete with W/B ratio of 0.50 had the compressive strengths of 33.9–41.9 MPa or 81–94% of OPC concrete. Furthermore, the compressive strength of concrete incorporation of ground POFA at 15% was the same as OPC concrete. The water permeability coefficient and the chloride ion penetration of POFA concrete were lower than OPC concrete when both types of concrete had the same compressive strengths. The findings also indicated that water permeability and chloride ion penetration of POFA concrete were significantly reduced compared to OPC concrete.

  10. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal), Class I

    Energy Technology Data Exchange (ETDEWEB)

    Bou-Mikael, Sami

    2002-02-05

    This project outlines a proposal to improve the recovery of light oil from waterflooded fluvial dominated deltaic (FDD) reservoir through a miscible carbon dioxide (CO2) flood. The site is the Port Neches Field in Orange County, Texas. The field is well explored and well exploited. The project area is 270 acres within the Port Neches Field.

  11. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal), Class I; FINAL

    International Nuclear Information System (INIS)

    Bou-Mikael, Sami

    2002-01-01

    This project outlines a proposal to improve the recovery of light oil from waterflooded fluvial dominated deltaic (FDD) reservoir through a miscible carbon dioxide (CO2) flood. The site is the Port Neches Field in Orange County, Texas. The field is well explored and well exploited. The project area is 270 acres within the Port Neches Field

  12. Measurement of the Rheology of Crude Oil in Equilibrium with CO2 at Reservoir Conditions.

    Science.gov (United States)

    Hu, Ruien; Crawshaw, John

    2017-06-06

    A rheometer system to measure the rheology of crude oil in equilibrium with carbon dioxide (CO2) at high temperatures and pressures is described. The system comprises a high-pressure rheometer which is connected to a circulation loop. The rheometer has a rotational flow-through measurement cell with two alternative geometries: coaxial cylinder and double gap. The circulation loop contains a mixer, to bring the crude oil sample into equilibrium with CO2, and a gear pump that transports the mixture from the mixer to the rheometer and recycles it back to the mixer. The CO2 and crude oil are brought to equilibrium by stirring and circulation and the rheology of the saturated mixture is measured by the rheometer. The system is used to measure the rheological properties of Zuata crude oil (and its toluene dilution) in equilibrium with CO2 at elevated pressures up to 220 bar and a temperature of 50 °C. The results show that CO2 addition changes the oil rheology significantly, initially reducing the viscosity as the CO2 pressure is increased and then increasing the viscosity above a threshold pressure. The non-Newtonian response of the crude is also seen to change with the addition of CO2.

  13. Application of MODFLOW for oil reservoir simulation during the Deepwater Horizon Crisis

    Science.gov (United States)

    Hsieh, Paul A.

    2011-01-01

    When the Macondo well was shut in on July 15, 2010, the shut-in pressure recovered to a level that indicated the possibility of oil leakage out of the well casing into the surrounding formation. Such a leak could initiate a hydraulic fracture that might eventually breach the seafloor, resulting in renewed and uncontrolled oil flow into the Gulf of Mexico. To help evaluate whether or not to reopen the well, a MODFLOW model was constructed within 24 h after shut in to analyze the shut-in pressure. The model showed that the shut-in pressure can be explained by a reasonable scenario in which the well did not leak after shut in. The rapid response provided a scientific analysis for the decision to keep the well shut, thus ending the oil spill resulting from the Deepwater Horizon blow out.

  14. Hydrodynamic thickness of petroleum oil adsorbed layers in the pores of reservoir rocks.

    Science.gov (United States)

    Alkafeef, Saad F; Algharaib, Meshal K; Alajmi, Abdullah F

    2006-06-01

    The hydrodynamic thickness delta of adsorbed petroleum (crude) oil layers into the pores of sandstone rocks, through which the liquid flows, has been studied by Poiseuille's flow law and the evolution of (electrical) streaming current. The adsorption of petroleum oil is accompanied by a numerical reduction in the (negative) surface potential of the pore walls, eventually stabilizing at a small positive potential, attributed to the oil macromolecules themselves. After increasing to around 30% of the pore radius, the adsorbed layer thickness delta stopped growing either with time or with concentrations of asphaltene in the flowing liquid. The adsorption thickness is confirmed with the blockage value of the rock pores' area determined by the combination of streaming current and streaming potential measurements. This behavior is attributed to the effect on the disjoining pressure across the adsorbed layer, as described by Derjaguin and Churaev, of which the polymolecular adsorption films lose their stability long before their thickness has approached the radius of the rock pore.

  15. Induced migration of fines during waterflooding in communicating layer-cake reservoirs

    DEFF Research Database (Denmark)

    Yuan, Hao; Shapiro, Alexander

    2011-01-01

    to more crossflow between layers and lowers the water sweep efficiency. However, this ratio facilitates the fluid diversion caused by the fines migration, leading to a more efficient enhanced oil recovery. The positive contribution from the mobility ratio to the increased oil recovery due to fines...... give rise to reduction of the permeability in water swept zones, which subsequently leads to the diversion of water flow from the initially more permeable layers to the less permeable ones. As a result, the displacement is more even, the water cut at the producer is decreased, and the oil recovery...... is increased. On the other hand, more energy for the pressure drop is required to maintain a constant flow rate. These effects are studied within a new upscaling model developed previously (Zhang et al., 2011). In a communicating layer cake reservoir, higher end-point mobility ratio (water to oil) leads...

  16. A Semi-Analytical Methodology for Multiwell Productivity Index of Well-Industry-Production-Scheme in Tight Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Guangfeng Liu

    2018-04-01

    Full Text Available Recently, the well-industry-production-scheme (WIPS has attracted more and more attention to improve tight oil recovery. However, multi-well pressure interference (MWPI induced by well-industry-production-scheme (WIPS strongly challenges the traditional transient pressure analysis methods, which focus on single multi-fractured horizontal wells (SMFHWs without MWPI. Therefore, a semi-analytical methodology for multiwell productivity index (MPI was proposed to study well performance of WIPS scheme in tight reservoir. To facilitate methodology development, the conceptual models of tight formation and WIPS scheme were firstly described. Secondly, seepage models of tight reservoir and hydraulic fractures (HFs were sequentially established and then dynamically coupled. Numerical simulation was utilized to validate our model. Finally, identification of flow regimes and sensitivity analysis were conducted. Our results showed that there was good agreement between our proposed model and numerical simulation; moreover, our approach also gave promising calculation speed over numerical simulation. Some expected flow regimes were significantly distorted due to WIPS. The slope of type curves which characterize the linear or bi-linear flow regime is bigger than 0.5 or 0.25. The horizontal line which characterize radial flow regime is also bigger 0.5. The smaller the oil rate, the more severely flow regimes were distorted. Well rate mainly determines the distortion of MPI curves, while fracture length, well spacing, fracture spacing mainly determine when the distortion of the MPI curves occurs. The bigger the well rate, the more severely the MPI curves are distorted. While as the well spacing decreases, fracture length increases, fracture spacing increases, occurrence of MWPI become earlier. Stress sensitivity coefficient mainly affects the MPI at the formation pseudo-radial flow stage, almost has no influence on the occurrence of MWPI. This work gains some

  17. The impact of in-situ stress and outcrop-based fracture geometry on hydraulic aperture and upscaled permeability in fractured reservoirs

    DEFF Research Database (Denmark)

    Bisdom, Kevin; Bertotti, Giovanni; Nick, Hamid

    2016-01-01

    explicitly, we quantify equivalent permeability, i.e. combined matrix and stress-dependent fracture flow. Fracture networks extracted from a large outcropping pavement form the basis of these models. The results show that the angle between fracture strike and σ 1 has a controlling impact on aperture...

  18. Inverse Problems in Geosciences: Modelling the Rock Properties of an Oil Reservoir

    DEFF Research Database (Denmark)

    Lange, Katrine

    . We have developed and implemented the Frequency Matching method that uses the closed form expression of the a priori probability density function to formulate an inverse problem and compute the maximum a posteriori solution to it. Other methods for computing models that simultaneously fit data...... of the subsurface of the reservoirs. Hence the focus of this work has been on acquiring models of spatial parameters describing rock properties of the subsurface using geostatistical a priori knowledge and available geophysical data. Such models are solutions to often severely under-determined, inverse problems...

  19. Using Chemicals to Optimize Conformance Control in Fractured Reservoirs; TOPICAL

    International Nuclear Information System (INIS)

    Seright, Randall S.; Liang, Jenn-Tai; Schrader, Richard; Hagstrom II, John; Wang, Ying; Kumar, Ananad; Wavrik, Kathryn

    2001-01-01

    This report describes work performed during the third and final year of the project, Using Chemicals to Optimize Conformance Control in Fractured Reservoirs. This research project had three objectives. The first objective was to develop a capability to predict and optimize the ability of gels to reduce permeability to water more than that to oil or gas. The second objective was to develop procedures for optimizing blocking agent placement in wells where hydraulic fractures cause channeling problems. The third objective was to develop procedures to optimize blocking agent placement in naturally fractured reservoirs

  20. Immiscible and Miscible Gas-Oil Gravity Drainage in Naturally Fractured Reservoirs

    NARCIS (Netherlands)

    Ameri, A.

    2014-01-01

    In the phase of declining oilfields and at a time when recovering hydrocarbons has becoming more difficult, effective techniques are the key to extract more oil from mature fields. The difficulty of developing effective techniques is often the real obstacle when dealing with heterogeneous formations

  1. The application of SEM in analyzing the damage to the petroleum reservoirs caused by drilling fluids

    International Nuclear Information System (INIS)

    Abdul Razak Ismail

    1996-01-01

    An experimental study has been conducted to analyze the damage to the potential oil and gas reservoirs due to the invasion of drilling fluid during drilling operation. Two types of rock samples representing low and high permeability were used to stimulate the petroleum reservoirs. Sea water based drilling fluids were used in this study. Detail observations to the rock samples were analyzed using scanning electron microscope (SEM). The results of both permeability restoration and SEM observation showed that severe permeability impairments were obtained for high permeability rock. These results indicate that the relative size of the barite particles and the pore size distribution and characteristics of the formation play an important role in determining the damage caused by the drilling fluids

  2. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    International Nuclear Information System (INIS)

    Allison, M. Lee; Chidsey, Thomas Jr.

    1999-01-01

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to about 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million bbl of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO-) flood 2 project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals

  3. Sodium butyrate attenuates soybean oil-based lipid emulsion-induced increase in intestinal permeability of lipopolysaccharide by modulation of P-glycoprotein in Caco-2 cells

    International Nuclear Information System (INIS)

    Yan, Jun-Kai; Gong, Zi-Zhen; Zhang, Tian; Cai, Wei

    2017-01-01

    Down-regulation of intestinal P-glycoprotein (P-gp) by soybean oil-based lipid emulsion (SOLE) may cause elevated intestinal permeability of lipopolysaccharide (LPS) in patients with total parenteral nutrition, but the appropriate preventative treatment is currently limited. Recently, sodium butyrate (NaBut) has been demonstrated to regulate the expression of P-gp. Therefore, this study aimed to address whether treatment with NaBut could attenuate SOLE-induced increase in intestinal permeability of LPS by modulation of P-gp in vitro. Caco-2 cells were exposed to SOLE with or without NaBut. SOLE-induced down-regulation of P-gp was significantly attenuated by co-incubation with NaBut. Nuclear recruitment of FOXO 3a in response to NaBut was involved in P-gp regulation. Transport studies revealed that SOLE-induced increase in permeability of LPS was significantly attenuated by co-incubation with NaBut. Collectively, our results suggested that NaBut may be a potentially useful medication to prevent SOLE-induced increase in intestinal permeability of LPS. - Highlights: • Caco-2 cells were used as models for studying parenteral nutrition in vitro. • NaBut restored SOLE-induced down-regulation of P-gp in Caco-2 cells. • Regulation of P-gp by NaBut was mediated via nuclear recruitment of FOXO 3a. • NaBut modulated the permeability of LPS by P-gp function, not barrier function.

  4. New geomechanical developments for reservoir management; Desenvolvimentos experimentais e computacionais para analises geomecanicas de reservatorio

    Energy Technology Data Exchange (ETDEWEB)

    Soares, Antonio C.; Menezes Filho, Armando Prestes; Silvestre, Jose R. [PETROBRAS S.A., Rio de Janeiro, RJ (Brazil). Centro de Pesquisas (CENPES)

    2008-07-01

    The common assumption that oil is produced under a constant rate only considering reservoir depletion has been questioned for some time. An usual hypothesis is that the physical properties of a reservoir are not constants during time, but they vary according to the properties of reservoir rock and the characteristics of the external loads. More precisely, as soon as a reservoir is explored, the volume of fluid diminishes, decreasing the static pressure and increasing the effective stress over the rock skeleton, which, depending on the nature of rock, can lead to a gradual deformation and alteration of reservoir's porosity and permeability, and oil productivity as well. This paper aims at showing numerical and experimental achievements, developed by the Well bore Engineering Technology Department of CENPES, devoted to the characterization of the influence of stress-strain states on the permeability and production of reservoir rocks. It is believed that these developments can possibly bring some light to the understanding of this complex phenomenon, besides allowing the establishment of more realistic relations involving stress-strain-permeability in coupled fluid dynamic problems. (author)

  5. Evaluation of the bottom water reservoir VAPEX process

    Energy Technology Data Exchange (ETDEWEB)

    Frauenfeld, T.W.J.; Jossy, C.; Kissel, G.A. [Alberta Research Council, Devon, AB (Canada); Rispler, K. [Saskatchewan Research Council, Saskatoon, SK (Canada)

    2004-07-01

    The mobilization of viscous heavy oil requires the dissolution of solvent vapour into the oil as well as the diffusion of the dissolved solvent into the virgin oil. Vapour extraction (VAPEX) is an enhanced oil recovery (EOR) process which involves injecting a solvent into the reservoir to reduce the viscosity of hydrocarbons. This paper describes the contribution of the Alberta Research Council to solvent-assisted oil recovery technology. The bottom water process was also modelled to determine its feasibility for a field-scale oil recovery scheme. Several experiments were conducted in an acrylic visual model in which Pujol and Boberg scaling were used to produce a lab model scaling a field process. The model simulated a slice of a 30 metre thick reservoir, with a 10 metre thick bottom water zone, containing two horizontal wells (25 metres apart) at the oil water interface. The experimental rates were found to be negatively affected by continuous low permeability layers and by oil with an initial gas content. In order to achieve commercial oil recovery rates, the bottom water process must be used to increase the surface area exposed to solvents. A large oil water interface between the wells provides contact for solvent when injecting gas at the interface. High production rates are therefore possible with appropriate well spacing. 11 refs., 4 tabs., 16 figs.

  6. Application of fractal theory in refined reservoir description for EOR pilot area

    Energy Technology Data Exchange (ETDEWEB)

    Yue Li; Yonggang Duan; Yun Li; Yuan Lu

    1997-08-01

    A reliable reservoir description is essential to investigate scenarios for successful EOR pilot test. Reservoir characterization includes formation composition, permeability, porosity, reservoir fluids and other petrophysical parameters. In this study, various new tools have been applied to characterize Kilamayi conglomerate formation. This paper examines the merits of various statistical methods for recognizing rock property correlation in vertical columns and gives out methods to determine fractal dimension including R/S analysis and power spectral analysis. The paper also demonstrates that there is obvious fractal characteristics in conglomerate reservoirs of Kilamayi oil fields. Well log data in EOR pilot area are used to get distribution profile of parameters including permeability, porosity, water saturation and shale content.

  7. Method for identifying subsurface fluid migration and drainage pathways in and among oil and gas reservoirs using 3-D and 4-D seismic imaging

    Science.gov (United States)

    Anderson, R.N.; Boulanger, A.; Bagdonas, E.P.; Xu, L.; He, W.

    1996-12-17

    The invention utilizes 3-D and 4-D seismic surveys as a means of deriving information useful in petroleum exploration and reservoir management. The methods use both single seismic surveys (3-D) and multiple seismic surveys separated in time (4-D) of a region of interest to determine large scale migration pathways within sedimentary basins, and fine scale drainage structure and oil-water-gas regions within individual petroleum producing reservoirs. Such structure is identified using pattern recognition tools which define the regions of interest. The 4-D seismic data sets may be used for data completion for large scale structure where time intervals between surveys do not allow for dynamic evolution. The 4-D seismic data sets also may be used to find variations over time of small scale structure within individual reservoirs which may be used to identify petroleum drainage pathways, oil-water-gas regions and, hence, attractive drilling targets. After spatial orientation, and amplitude and frequency matching of the multiple seismic data sets, High Amplitude Event (HAE) regions consistent with the presence of petroleum are identified using seismic attribute analysis. High Amplitude Regions are grown and interconnected to establish plumbing networks on the large scale and reservoir structure on the small scale. Small scale variations over time between seismic surveys within individual reservoirs are identified and used to identify drainage patterns and bypassed petroleum to be recovered. The location of such drainage patterns and bypassed petroleum may be used to site wells. 22 figs.

  8. Geothermal Permeability Enhancement - Final Report

    Energy Technology Data Exchange (ETDEWEB)

    Joe Beall; Mark Walters

    2009-06-30

    The overall objective is to apply known permeability enhancement techniques to reduce the number of wells needed and demonstrate the applicability of the techniques to other undeveloped or under-developed fields. The Enhanced Geothermal System (EGS) concept presented in this project enhances energy extraction from reduced permeability zones in the super-heated, vapor-dominated Aidlin Field of the The Geysers geothermal reservoir. Numerous geothermal reservoirs worldwide, over a wide temperature range, contain zones of low permeability which limit the development potential and the efficient recovery of heat from these reservoirs. Low permeability results from poorly connected fractures or the lack of fractures. The Enhanced Geothermal System concept presented here expands these technologies by applying and evaluating them in a systematic, integrated program.

  9. Tailor-made surfactants for optimized chemical EOR. Meeting oil reservoir conditions by applied knowledge of structure-performance relationship in extended surfactants

    Energy Technology Data Exchange (ETDEWEB)

    Trahan, G.; Sorensen, W. [Sasol North America Inc., Westlake, LA (United States); Jakobs-Sauter, B. [Sasol Germany GmbH (Germany)

    2013-08-01

    Formulating the surfactant package for chemical EOR is a time consuming and expensive process - the formulation needs to fit the specific reservoir conditions (like oil type, temperature, salinity, etc.) to give optimum performance and the number of formulation variables is virtually endless. This paper studies the impact of surfactant structure on EOR formulation ability and performance and how to adjust the structure of the surfactant molecule to meet a specific reservoir's needs. Data from salinity phase boundary studies of alcohol propoxy sulfates illustrate how changes in alcohol structure as well as in propylene oxide level can shift optimum salinity and temperature to the desired range in a given model oil. From these data the impact of individual structural units was evaluated. Application of the HLD model (Hydrophilic-Lipophilic Deviation) shows how to extrapolate from the known data set to actual reservoir conditions. This is illustrated by studies on crude oil samples. Additional tests study how effective the selected surfactants perform. The HLD concept proves to be a valuable tool to select and tailor surfactants to individual reservoir needs, thus simplifying the surfactant screening process for EOR formulations by pre-selection of suitable structures and ultimately reducing cost and effort on the way to the most effective chemical EOR package. (orig.)

  10. CO2 Huff-n-Puff process in a light oil shallow shelf carbonate reservoir. Annual report, January 1, 1995--December 31, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Wehner, S.C.; Boomer, R.J.; Cole, R.; Preiditus, J.; Vogt, J.

    1996-09-01

    The application of cyclic CO{sub 2}, often referred to as the CO{sub 2} Huff-n-Puff process, may find its niche in the maturing waterfloods of the Permian Basin. Coupling the CO{sub 2} H-n-P process to miscible flooding applications could provide the needed revenue to sufficiently mitigate near-term negative cash flow concerns in the capital intensive miscible projects. Texaco Exploration & Production Inc. and the U.S. Department of Energy have teamed up in an attempt to develop the CO{sub 2} Huff-n-Puff process in the Grayburg/San Andres formation; a light oil, shallow shelf carbonate reservoir within the Permian Basin. This cost-shared effort is intended to demonstrate the viability of this underutilized technology in a specific class of domestic reservoir. A significant amount of oil reserves are located in carbonate reservoirs. Specifically, the carbonates deposited in shallow shelf (SSC) environments make up the largest percentage of known reservoirs within the Permian Basin of North America. Many of these known resources have been under waterflooding operations for decades and are at risk of abandonment if crude oil recoveries cannot be economically enhanced. The selected site for this demonstration project is the Central Vacuum Unit waterflood in Lea County, New Mexico.

  11. An Integrated Capillary, Buoyancy, and Viscous-Driven Model for Brine/CO2Relative Permeability in a Compositional and Parallel Reservoir Simulator

    KAUST Repository

    Kong, X.; Delshad, M.; Wheeler, M. F.

    2012-01-01

    The effectiveness of CO2 storage in the saline aquifers is governed by the interplay of capillary, viscous, and buoyancy forces. Recent experimental study reveals the impact of pressure, temperature, and salinity on interfacial tension (IFT) between CO2 and brine. The dependence of CO2-brine relative permeability and capillary pressure on pressure (IFT) is also clearly evident in published experimental results. Improved understanding of the mechanisms that control the migration and trapping of CO2 in subsurface is crucial to design future storage projects that warrant long-term and safe containment. Simulation studies ignoring the buoyancy and also variation in interfacial tension and the effect on the petrophysical properties such as trapped CO2 saturations, relative permeability, and capillary pressure have a poor chance of making accurate predictions of CO2 injectivity and plume migration. We have developed and implemented a general relative permeability model that combines effects of pressure gradient, buoyancy, and IFT in an equation of state (EOS) compositional and parallel simulator. The significance of IFT variations on CO2 migration and trapping is assessed.

  12. An Integrated Capillary, Buoyancy, and Viscous-Driven Model for Brine/CO2Relative Permeability in a Compositional and Parallel Reservoir Simulator

    KAUST Repository

    Kong, X.

    2012-11-03

    The effectiveness of CO2 storage in the saline aquifers is governed by the interplay of capillary, viscous, and buoyancy forces. Recent experimental study reveals the impact of pressure, temperature, and salinity on interfacial tension (IFT) between CO2 and brine. The dependence of CO2-brine relative permeability and capillary pressure on pressure (IFT) is also clearly evident in published experimental results. Improved understanding of the mechanisms that control the migration and trapping of CO2 in subsurface is crucial to design future storage projects that warrant long-term and safe containment. Simulation studies ignoring the buoyancy and also variation in interfacial tension and the effect on the petrophysical properties such as trapped CO2 saturations, relative permeability, and capillary pressure have a poor chance of making accurate predictions of CO2 injectivity and plume migration. We have developed and implemented a general relative permeability model that combines effects of pressure gradient, buoyancy, and IFT in an equation of state (EOS) compositional and parallel simulator. The significance of IFT variations on CO2 migration and trapping is assessed.

  13. Post waterflood CO{sub 2} miscible flood in light oil, fluvial-dominated deltaic reservoir. Annual report, October 1, 1993--September 30, 1994

    Energy Technology Data Exchange (ETDEWEB)

    Bou-Mikael, S.

    1995-07-01

    Texaco Exploration and Production Inc. (TEPI) and the U.S. Department of Energy (DOE) entered into a cost sharing cooperative agreement to conduct an Enhanced Oil Recovery demonstration project at Port Neches. The field is located in Orange County near Beaumont, Texas. The project will demonstrate the effectiveness of the CO{sub 2}, miscible process in Fluvial Dominated Deltaic reservoirs. It will also evaluate the use of horizontal CO{sub 2} injection wells to improve the overall sweep efficiency. A data base of FDD reservoirs for the gulf coast region will be developed by LSU, using a screening model developed by Texaco Research Center in Houston. Finally, the results and the information gained from this project will be disseminated throughout the oil industry via a series of SPE papers and industry open forums. Reservoir characterization efforts for the Marginulina sand, are in progress utilizing conventional and advanced technologies including 3-D seismic. Sidewall and conventional. cores were cut and analyzed, lab tests were conducted on reservoir fluids, reservoir BHP pressure and reservoir voidage were monitored as shown. Texaco is utilizing the above data to develop a Stratamodel to best describe and characterize the reservoir and to use it as an input for the compositional simulator. The current compositional model is being revised to integrate the new data from the 3-D seismic and field performance under CO{sub 2} injection, to ultimately develop an accurate economic model. All facilities work has been completed and placed in service including the CO{sub 2} pipeline and metering equipment, CO{sub 2} injection and production equipment, water injection equipment, well work and injection/production lines. The horizontal injection well was drilled and completed on January 15, 1994. CO{sub 2} purchases from Cardox continue at an average rate of 3600 MCFD. The CO{sub 2} is being injected at line pressure of 1350 psi.

  14. Adaptive Methods for Permeability Estimation and Smart Well Management

    Energy Technology Data Exchange (ETDEWEB)

    Lien, Martha Oekland

    2005-04-01

    The main focus of this thesis is on adaptive regularization methods. We consider two different applications, the inverse problem of absolute permeability estimation and the optimal control problem of estimating smart well management. Reliable estimates of absolute permeability are crucial in order to develop a mathematical description of an oil reservoir. Due to the nature of most oil reservoirs, mainly indirect measurements are available. In this work, dynamic production data from wells are considered. More specifically, we have investigated into the resolution power of pressure data for permeability estimation. The inversion of production data into permeability estimates constitutes a severely ill-posed problem. Hence, regularization techniques are required. In this work, deterministic regularization based on adaptive zonation is considered, i.e. a solution approach with adaptive multiscale estimation in conjunction with level set estimation is developed for coarse scale permeability estimation. A good mathematical reservoir model is a valuable tool for future production planning. Recent developments within well technology have given us smart wells, which yield increased flexibility in the reservoir management. In this work, we investigate into the problem of finding the optimal smart well management by means of hierarchical regularization techniques based on multiscale parameterization and refinement indicators. The thesis is divided into two main parts, where Part I gives a theoretical background for a collection of research papers that has been written by the candidate in collaboration with others. These constitutes the most important part of the thesis, and are presented in Part II. A brief outline of the thesis follows below. Numerical aspects concerning calculations of derivatives will also be discussed. Based on the introduction to regularization given in Chapter 2, methods for multiscale zonation, i.e. adaptive multiscale estimation and refinement

  15. Genome-Resolved Metagenomic Analysis Reveals Roles for Candidate Phyla and Other Microbial Community Members in Biogeochemical Transformations in Oil Reservoirs.

    Science.gov (United States)

    Hu, Ping; Tom, Lauren; Singh, Andrea; Thomas, Brian C; Baker, Brett J; Piceno, Yvette M; Andersen, Gary L; Banfield, Jillian F

    2016-01-19

    Oil reservoirs are major sites of methane production and carbon turnover, processes with significant impacts on energy resources and global biogeochemical cycles. We applied a cultivation-independent genomic approach to define microbial community membership and predict roles for specific organisms in biogeochemical transformations in Alaska North Slope oil fields. Produced water samples were collected from six locations between 1,128 m (24 to 27°C) and 2,743 m (80 to 83°C) below the surface. Microbial community complexity decreased with increasing temperature, and the potential to degrade hydrocarbon compounds was most prevalent in the lower-temperature reservoirs. Sulfate availability, rather than sulfate reduction potential, seems to be the limiting factor for sulfide production in some of the reservoirs under investigation. Most microorganisms in the intermediate- and higher-temperature samples were related to previously studied methanogenic and nonmethanogenic archaea and thermophilic bacteria, but one candidate phylum bacterium, a member of the Acetothermia (OP1), was present in Kuparuk sample K3. The greatest numbers of candidate phyla were recovered from the mesothermic reservoir samples SB1 and SB2. We reconstructed a nearly complete genome for an organism from the candidate phylum Parcubacteria (OD1) that was abundant in sample SB1. Consistent with prior findings for members of this lineage, the OD1 genome is small, and metabolic predictions support an obligately anaerobic, fermentation-based lifestyle. At moderate abundance in samples SB1 and SB2 were members of bacteria from other candidate phyla, including Microgenomates (OP11), Atribacteria (OP9), candidate phyla TA06 and WS6, and Marinimicrobia (SAR406). The results presented here elucidate potential roles of organisms in oil reservoir biological processes. The activities of microorganisms in oil reservoirs impact petroleum resource quality and the global carbon cycle. We show that bacteria

  16. Diagenesis and reservoir quality of the Lower Cretaceous Quantou Formation tight sandstones in the southern Songliao Basin, China

    Science.gov (United States)

    Xi, Kelai; Cao, Yingchang; Jahren, Jens; Zhu, Rukai; Bjørlykke, Knut; Haile, Beyene Girma; Zheng, Lijing; Hellevang, Helge

    2015-12-01

    The Lower Cretaceous Quantou Formation in the southern Songliao Basin is the typical tight oil sandstone in China. For effective exploration, appraisal and production from such a tight oil sandstone, the diagenesis and reservoir quality must be thoroughly studied first. The tight oil sandstone has been examined by a variety of methods, including core and thin section observation, XRD, SEM, CL, fluorescence, electron probing analysis, fluid inclusion and isotope testing and quantitative determination of reservoir properties. The sandstones are mostly lithic arkoses and feldspathic litharenites with fine to medium grain size and moderate to good sorting. The sandstones are dominated by feldspar, quartz, and volcanic rock fragments showing various stages of disintegration. The reservoir properties are quite poor, with low porosity (average 8.54%) and permeability (average 0.493 mD), small pore-throat radius (average 0.206 μm) and high displacement pressure (mostly higher than 1 MPa). The tight sandstone reservoirs have undergone significant diagenetic alterations such as compaction, feldspar dissolution, quartz cementation, carbonate cementation (mainly ferrocalcite and ankerite) and clay mineral alteration. As to the onset time, the oil emplacement was prior to the carbonate cementation but posterior to the quartz cementation and feldspar dissolution. The smectite to illite reaction and pressure solution at stylolites provide a most important silica sources for quartz cementation. Carbonate cements increase towards interbedded mudstones. Mechanical compaction has played a more important role than cementation in destroying the reservoir quality of the K1q4 sandstone reservoirs. Mixed-layer illite/smectite and illite reduced the porosity and permeability significantly, while chlorite preserved the porosity and permeability since it tends to be oil wet so that later carbonate cementation can be inhibited to some extent. It is likely that the oil emplacement occurred

  17. Mouillabilité et réservoirs pétroliers Wettability and Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Cuiec L.

    2006-11-01

    Full Text Available Dans la première partie de cet article, des considérations générales relatives à la mouillabilité sont exposées, en particulier sur les points suivants : - définition; - importance sur le comportement d'un système milieu poreux/fluide 1/fluide 2; - méthodes d'évaluation. Puis, différents aspects des problèmes posés par ce paramètre lors de l'étude des gisements sont abordés. Tout d'abord, le problème de l'obtention d'échantillons de roche-réservoir ayant des propriétés de surface représentatives est examiné; en effet, une telle obtention est indispensable pour réaliser des expériences de laboratoire significatives. Les causes de modification des propriétés de surface entre le réservoir et le laboratoire sont passées en revue. L'impossibilité d'empêcher à coup sûr de telles modifications justifie l'utilisation d'une procédure de restauration des propriétés originelles qui est ensuite décrite. L'existence de réservoirs non mouillables à l'eau n'est pas aussi rare que d'aucuns le pensaient il y a seulement une dizaine d'années. De nombreux travaux extraits de la littérature ou réalisés à l'Institut Français du Pétrole (IFP illustrent ce point. Enfin, l'état des connaissances concernant l'origine de la non-mouillabilité à l'eau est présenté. In the first part of this paper, general considerations about wettability are given, including:(a definition;(b importance of this parameter on the behavior of a porous-medium/fluid 1/fluid 2 system;(c methods of evaluation. Then we will examine various aspects of problems that arise for petroleum engineers because of this parameter. First of all, we will take up the problem of obtaining representative samples from the standpoint of surface properties. Obtaining such samples is indispensable for performing meaningful laboratory experiments. The causes of changes, in the surface properties of reservoir rock samples between the field and the laboratory will be

  18. Combined reservoir simulation and seismic technology, a new approach for modeling CHOPS

    Energy Technology Data Exchange (ETDEWEB)

    Aghabarati, H.; Lines, L.; Settari, A. [Calgary Univ., AB (Canada); Dumitrescu, C. [Sensor Geophysical Ltd., Calgary, AB (Canada)

    2008-10-15

    One of the primary recovery schemes for developing heavy oil reservoirs in Canada is cold heavy oil production with sand (CHOPS). With the introduction of progressive cavity pumps, CHOPS can be applied in unconsolidated or weakly consolidated formations. In order to better understand reservoir properties and recovery mechanism, this paper discussed the use of a combined reservoir simulation and seismic technology that were applied for a heavy oil reservoir situated in Saskatchewan, Canada. Using a seismic survey acquired in 1989, the study used geostatistical methods to estimate the initial reservoir porosity. Sand production was then modeled using an erosional velocity approach and the model was run based on oil production. The paper also compared the results of true porosity derived from simulation against the porosity estimated from a second seismic survey acquired in 2001. Last, the extent and the shape of the enhanced permeability region was modelled in order to estimate porosity distribution. It was concluded that the performance of the CHOPS wells depended greatly on the rate of creation of the high permeability zone around the wells. 9 refs., 2 tabs., 18 figs., 1 appendix.

  19. Determination of Three-Phase Relative Permeabilities under Reservoir Conditions by Hot Water and Steamflood Experiments Détermination de perméabilités relatives tri-phasiques en conditions de réservoir, à partir d'expériences de balayages à l'eau chaude et à la vapeur

    Directory of Open Access Journals (Sweden)

    Quettier L.

    2006-11-01

    Full Text Available In order to help the physical and numerical interpretation of Emeraude's steam pilot, two-phase waterfloods at four temperatures (between 30 and 240°C and a steamflood were performed in the laboratory using the same porous medium (compacted silt and under reservoir conditions. Dynamic isothermal displacements were interpreted with a thermal simulator taking into account capillary end effects. The corresponding oil-water relative permeability curves were obtained by matching observed pressure drop and oil production. Results show that temperature influences the end-point saturations but not the shape of the curves. The steamflood experiment was carried out in an adiabatic core holder. Oil stripping and production of a large amount of CO2 caused by dissolution of carbonates were pointed out. The numerical interpretation of this experiment, by making use of the oil-water relative permeabilities, provided the three-phase oil relative permeability which is an essential datum for numerical interpretation of a steam drive pilot. Then a parameter study was used to quantify the influence of the different mechanisms involved in hot water and steam floods. Dans le but de faciliter l'interprétation physique et numérique du pilote vapeur d' Emeraude, des balayages eau-huile à quatre températures (entre 30 et 240°C et un balayage à la vapeur ont été réalisés au laboratoire. Toutes ces expériences ont été effectuées sur le même milieu poreux (silt compacté et en conditions de réservoir. Les déplacements bi-phasiques isothermes, en écoulement transitoire, ont été interprétés avec un modèle numérique thermique qui prend en compte les effets capillaires aux extrémités de l'échantillon. Les courbes de perméabilités relatives dynamiques eau-huile sont déterminées par calage, sur les courbes expérimentales, de la différence de pression et de la production d'huile simulées. Les résultats montrent que la température influe sur les

  20. Blocking effect and numerical study of polymer particles dispersion flooding in heterogeneous reservoir

    Science.gov (United States)

    Zhu, Weiyao; Li, Jianhui; Lou, Yu

    2018-02-01

    Polymer flooding has become an effective way to improve the sweep efficiency in many oil fields. Many scholars have carried out a lot of researches on the mechanism of polymer flooding. In this paper, the effect of polymer on seepage is analyzed. The blocking effect of polymer particles was studied experimentally, and the residual resistance coefficient (RRF) were used to represent the blocking effect. We also build a mathematical model for heterogeneous concentration distribution of polymer particles. Furthermore, the effects of polymer particles on reservoir permeability, fluid viscosity and relative permeability are considered, and a two-phase flow model of oil and polymer particles is established. In addition, the model was tested in the heterogeneous stratum model, and three influencing factors, such as particle concentration, injection volume and PPD (short for polymer particle dispersion) injection time, were analyzed. Simulation results show that PPD can effectively improve sweep efficiency and especially improve oil recovery of low permeability layer. Oil recovery increases with the increase of particle concentration, but oil recovery increase rate gradually decreases with that. The greater the injected amount of PPD, the greater oil recovery and the smaller oil recovery increase rate. And there is an optimal timing to inject PPD for specific reservoir.

  1. How Specific Microbial Communities Benefit the Oil Industry: Case Study - Proof of Concept that Oil Entrained in Marginal Reservoirs Can Be Bioconverted to Methane Gas as a Green Energy Recovery Strategy

    Science.gov (United States)

    Gieg, Lisa

    Conventional oil recovery techniques such as water flooding typically remove only up to 40% of the oil present in reservoirs. Enhanced oil recovery (EOR) techniques are considered tertiary strategies that may be applied to recover a greater volume of oil. In particular, the use of microorganisms to aid in oil production (microbial-enhanced oil recovery or MEOR) is considered a green energy recovery strategy since microbial processes do not require large amounts of energy input and can potentially produce large amounts of useful byproducts from inexpensive and renewable resources (Youssef et al., 2008). These byproducts can include the generation of