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...

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.

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

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

Calculation of large scale relative permeabilities from stochastic properties of the permeability field and fluid properties

Energy Technology Data Exchange (ETDEWEB)

Lenormand, R.; Thiele, M.R. [Institut Francais du Petrole, Rueil Malmaison (France)

1997-08-01

The paper describes the method and presents preliminary results for the calculation of homogenized relative permeabilities using stochastic properties of the permeability field. In heterogeneous media, the spreading of an injected fluid is mainly sue to the permeability heterogeneity and viscosity fingering. At large scale, when the heterogeneous medium is replaced by a homogeneous one, we need to introduce a homogenized (or pseudo) relative permeability to obtain the same spreading. Generally, is derived by using fine-grid numerical simulations (Kyte and Berry). However, this operation is time consuming and cannot be performed for all the meshes of the reservoir. We propose an alternate method which uses the information given by the stochastic properties of the field without any numerical simulation. The method is based on recent developments on homogenized transport equations (the {open_quotes}MHD{close_quotes} equation, Lenormand SPE 30797). The MHD equation accounts for the three basic mechanisms of spreading of the injected fluid: (1) Dispersive spreading due to small scale randomness, characterized by a macrodispersion coefficient D. (2) Convective spreading due to large scale heterogeneities (layers) characterized by a heterogeneity factor H. (3) Viscous fingering characterized by an apparent viscosity ration M. In the paper, we first derive the parameters D and H as functions of variance and correlation length of the permeability field. The results are shown to be in good agreement with fine-grid simulations. The are then derived a function of D, H and M. The main result is that this approach lead to a time dependent . Finally, the calculated are compared to the values derived by history matching using fine-grid numerical simulations.

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.

A Direct inverse model to determine permeability fields from pressure and flow rate measurements

NARCIS (Netherlands)

Brouwer, G.K.; Fokker, P.A.; Wilschut, F.; Zijl, W.

2008-01-01

The determination of the permeability field from pressure and flow rate measurements in wells is a key problem in reservoir engineering. This paper presents a Double Constraint method for inverse modeling that is an example of direct inverse modeling. The method is used with a standard

Hydrogeochemistry and reservoir model of Fuzhou geothermal field, China

Science.gov (United States)

Huang, H. F.; Goff, Fraser

1986-03-01

Fuzhou geothermal field is a low- to intermediate-temperature geothermal system consisting of meteoric water that circulates deeply along faults. The area of the field is about 9 km 2 but it is elongated in a NNW-trending direction. Fluids in the field are controlled by a series of four NNW extensional faults in Cretaceous granitic basement (Fuzhou fault zone). These faults feed warm waters into overlying permeable Quaternary sediments. The hydrothermal system consists of north and south parts whose chemical compositions are subtly different. In the northern part the system discharges sulfate/chloride waters with relatively low chloride concentrations, but in the south the system discharges chloride waters having relatively high chloride concentrations. Maximum wellhead temperatures are 97°C, which agrees with the chalcedony geothermometer in many cases. Based on the solubility of quartz, the deep-reservoir temperature cannot exceed 123 to 131°C. From heat and mass balance calculations, we conclude that the present total extracted capacity of fluid from the reservoir (20,000 tons/day) could be doubled without noticeable drawdown. We estimate the recoverable heat in the reservoir to be about 1.71 × 10 11 MJ.

Numerical simulation of electricity generation potential from fractured granite reservoir through vertical wells at Yangbajing geothermal field

International Nuclear Information System (INIS)

Zeng, Yu-chao; Zhan, Jie-min; Wu, Neng-you; Luo, Ying-ying; Cai, Wen-hao

2016-01-01

Yangbajing geothermal field is the first high-temperature hydrothermal convective geothermal system in China. Research and development of the deep fractured granite reservoir is of great importance for capacity expanding and sustaining of the ground power plant. The geological exploration found that there is a fractured granite heat reservoir at depth of 950–1350 m in well ZK4001 in the north of the geothermal field, with an average temperature of 248 °C and a pressure of 8.01–11.57 MPa. In this work, electricity generation potential and its dependent factors from this fractured granite reservoir by water circulating through vertical wells are numerically investigated. The results indicate that the vertical well system attains an electric power of 16.8–14.7 MW, a reservoir impedance of 0.29–0.46 MPa/(kg/s) and an energy efficiency of about 29.6–12.8 during an exploiting period of 50 years under reference conditions, showing good heat production performance. The main parameters affecting the electric power are water production rate and injection temperature. The main parameters affecting reservoir impedance are reservoir permeability, injection temperature and water production rate. The main parameters affecting the energy efficiency are reservoir permeability, injection temperature and water production rate. Higher reservoir permeability or more reasonable injection temperature or water production rate within certain ranges will be favorable for improving the electricity generation performance. - Highlights: • We established a numerical model of vertical well heat mining system. • Desirable electricity production performance can be obtained under suitable conditions. • The system attains an electric power of 16.8–14.7 MW with an efficiency of about 29.6–12.8. • Electric power mainly depends on water production rate and injection temperature. • Higher permeability within a certain range is favorable for electricity generation.

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.

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.

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.

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.

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

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.

Paragenetic evolution of reservoir facies, Middle Triassic Halfway Formation, PeeJay Field, northeastern British Columbia: controls on reservoir quality

Energy Technology Data Exchange (ETDEWEB)

Caplan, M. L. [Alberta Univ., Dept. of Earth and Atmospheric Sciences, Edmonton, AB (Canada); Moslow, T. F. [Ulster Petroleum Ltd., Calgary, AB (Canada)

1998-09-01

Because of the obvious importance of reservoir quality to reservoir performance, diagenetic controls on reservoir quality of Middle Triassic reservoir facies are investigated by comparing two reservoir lithofacies. The implications of porosity structure on the efficiency of primary and secondary hydrocarbon recovery are also assessed. Halfway reservoir facies are composed of bioclastic grainstones (lithofacies G) and litharenites/sublitharenites (lithofacies H), both of which are interpreted as tidal inlet fills. Although paragenetic evolution was similar for the two reservoir facies, subtle differences in reservoir quality are discernible. These are controlled by sedimentary structures, porosity type, grain constituents, and degree of cementation. Reservoir quality in lithofacies G is a function of connectivity of the pore network. In lithofacies H, secondary granular porosity creates a more homogeneous interconnected pore system, wide pore throats and low aspect ratios. The high porosity and low permeability values of the bioclastic grainstones are suspected to cause inefficient flushing of hydrocarbons during waterflooding. However, it is suggested that recovery may be enhanced by induced hydraulic fracturing and acidization of lower permeability calcareous cemented zones. 52 refs., 15 figs.

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.

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

The Ahuachapan geothermal field, El Salvador: Reservoir analysis

Energy Technology Data Exchange (ETDEWEB)

Aunzo, Z.; Bodvarsson, G.S.; Laky, C.; Lippmann, M.J.; Steingrimsson, B.; Truesdell, A.H.; Witherspoon, P.A. (Lawrence Berkeley Lab., CA (USA); Icelandic National Energy Authority, Reykjavik (Iceland); Geological Survey, Menlo Park, CA (USA); Lawrence Berkeley Lab., CA (USA))

1989-08-01

The Earth Sciences Division of Lawrence Berkeley Laboratory (LBL) is conducting a reservoir evaluation study of the Ahuachapan geothermal field in El Salvador. This work is being performed in cooperation with the Comision Ejecutiva Hidroelectrica del Rio Lempa (CEL) and the Los Alamos National Laboratory (LANL). This report describes the work done during the first year of the study (FY 1988--89), and includes the (1) development of geological and conceptual models of the field, (2) evaluation of the initial thermodynamic and chemical conditions and their changes during exploitation, (3) evaluation of interference test data and the observed reservoir pressure decline, and (4) the development of a natural state model for the field. The geological model of the field indicates that there are seven (7) major and five (5) minor faults that control the fluid movement in the Ahuachapan area. Some of the faults act as a barrier to flow as indicated by large temperature declines towards the north and west. Other faults act as preferential pathways to flow. The Ahuachapan Andesites provide good horizontal permeability to flow and provide most of the fluids to the wells. The underlying Older Agglomerates also contribute to well production, but considerably less than the Andesites. 84 refs.

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.

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.

Reservoir characterization by multiattribute analysis: The Orito field case

Directory of Open Access Journals (Sweden)

Montes Luis

2010-12-01

Full Text Available

In order to characterize the Caballos formation reservoir in the Orito field in the Putumayo basin - Colombia, a multiattribute analysis was applied to a 50 km2 seismic volume along with 16 boreholes. Some properties of the reservoir were reliably estimated and very accurate when compared with well data. The porosity, permeability and volume of shale were calculated in the seismic volume by at least second order multivariate polynomial. A good correlation between porosity and acoustic impedance was observed by means of crossplot analysis performed on properties measured and estimated in cores or borehole logs as well as on properties calculated in the seismic volume. The estimated property values were well behaved according to the rocks physics analysis. With the property maps generated and the geological environments of the reservoir a new interpretation of the Caballos formation was established. High correlation coefficients and low estimated errors point out competence to calculate these three reservoir properties in places far from the influence of the wells. The multiple equation system was established through weighted hierarchical grouping of attributes and their coefficients calculated applying the inverse generalized matrix method.

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.

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

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...

Decoupling damage mechanisms in acid-fractured gas/condensate reservoirs

Energy Technology Data Exchange (ETDEWEB)

Bachman, R.C.; Walters, D.A. [Taurus Reservoir Solutions Ltd., Calgary, AB (Canada); Settari, A. [Calgary Univ., AB (Canada); Rahim, Z.; Ahmed, M.S. [Saudi Aramco, Dhahran (Saudi Arabia)

2006-07-01

The Khuff is a gas condensate field located 11,500 feet beneath the producing Ghawar oil field in Saudi Arabia. Wells are mainly acid fracture stimulated following drilling with excellent fracture conductivity and length properties. The wells experience a quick production loss however, after tie-in which eventually stabilizes after two to five months. In order to identify the source of productivity loss, such as near well liquid dropout, fracture conductivity loss, reservoir permeability loss due to increased effective stress, a study of a well in the Khuff field was conducted. The study reviewed basic geomechanical and reservoir properties and identified the mechanisms of production loss. The paper presented the methodology, data and preliminary analysis, relative permeability and results of the history matching. It was concluded that traditional production type curves in cases with changing skin may indicate that transient flow is occurring when boundary effects are felt. In addition, stress dependent fracture conductivity and reservoir permeability can be modeled with simpler pressure dependent functions for relatively low overall loss in reservoir pressure. 30 refs., 25 figs., 1 appendix.

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

Reservoir Characterization of Bridgeport and Cypress Sandstones in Lawrence Field Illinois to Improve Petroleum Recovery by Alkaline-Surfactant-Polymer Flood

Energy Technology Data Exchange (ETDEWEB)

Seyler, Beverly; Grube, John; Huff, Bryan; Webb, Nathan; Damico, James; Blakley, Curt; Madhavan, Vineeth; Johanek, Philip; Frailey, Scott

2012-12-21

Within the Illinois Basin, most of the oilfields are mature and have been extensively waterflooded with water cuts that range up to 99% in many of the larger fields. In order to maximize production of significant remaining mobile oil from these fields, new recovery techniques need to be researched and applied. The purpose of this project was to conduct reservoir characterization studies supporting Alkaline-Surfactant-Polymer Floods in two distinct sandstone reservoirs in Lawrence Field, Lawrence County, Illinois. A project using alkaline-surfactantpolymer (ASP) has been established in the century old Lawrence Field in southeastern Illinois where original oil in place (OOIP) is estimated at over a billion barrels and 400 million barrels have been recovered leaving more than 600 million barrels as an EOR target. Radial core flood analysis using core from the field demonstrated recoveries greater than 20% of OOIP. While the lab results are likely optimistic to actual field performance, the ASP tests indicate that substantial reserves could be recovered even if the field results are 5 to 10% of OOIP. Reservoir characterization is a key factor in the success of any EOR application. Reservoirs within the Illinois Basin are frequently characterized as being highly compartmentalized resulting in multiple flow unit configurations. The research conducted on Lawrence Field focused on characteristics that define reservoir compartmentalization in order to delineate preferred target areas so that the chemical flood can be designed and implemented for the greatest recovery potential. Along with traditional facies mapping, core analyses and petrographic analyses, conceptual geological models were constructed and used to develop 3D geocellular models, a valuable tool for visualizing reservoir architecture and also a prerequisite for reservoir simulation modeling. Cores were described and potential permeability barriers were correlated using geophysical logs. Petrographic analyses

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...

Characterization and estimation of permeability correlation structure from performance data

Energy Technology Data Exchange (ETDEWEB)

Ershaghi, I.; Al-Qahtani, M. [Univ. of Southern California, Los Angeles, CA (United States)

1997-08-01

In this study, the influence of permeability structure and correlation length on the system effective permeability and recovery factors of 2-D cross-sectional reservoir models, under waterflood, is investigated. Reservoirs with identical statistical representation of permeability attributes are shown to exhibit different system effective permeability and production characteristics which can be expressed by a mean and variance. The mean and variance are shown to be significantly influenced by the correlation length. Detailed quantification of the influence of horizontal and vertical correlation lengths for different permeability distributions is presented. The effect of capillary pressure, P{sub c1} on the production characteristics and saturation profiles at different correlation lengths is also investigated. It is observed that neglecting P{sub c} causes considerable error at large horizontal and short vertical correlation lengths. The effect of using constant as opposed to variable relative permeability attributes is also investigated at different correlation lengths. Next we studied the influence of correlation anisotropy in 2-D reservoir models. For a reservoir under five-spot waterflood pattern, it is shown that the ratios of breakthrough times and recovery factors of the wells in each direction of correlation are greatly influenced by the degree of anisotropy. In fully developed fields, performance data can aid in the recognition of reservoir anisotropy. Finally, a procedure for estimating the spatial correlation length from performance data is presented. Both the production performance data and the system`s effective permeability are required in estimating the correlation length.

Integrating geologic and engineering data into 3-D reservoir models: an example from norman wells field, NWT, Canada

International Nuclear Information System (INIS)

Yose, L.A.

2004-01-01

A case study of the Norman Wells field will be presented to highlight the work-flow and data integration steps associated with characterization and modeling of a complex hydrocarbon reservoir. Norman Wells is a Devonian-age carbonate bank ('reef') located in the Northwest Territories of Canada, 60 kilometers south of the Arctic Circle. The reservoir reaches a maximum thickness of 130 meters in the reef interior and thins toward the basin due to depositional pinch outs. Norman Wells is an oil reservoir and is currently under a 5-spot water injection scheme for enhanced oil recovery (EOR). EOR strategies require a detailed understanding of how reservoir flow units, flow barriers and flow baffles are distributed to optimize hydrocarbon sweep and recovery and to minimize water handling. Reservoir models are routinely used by industry to characterize the 3-D distribution of reservoir architecture (stratigraphic layers, depositional facies, faults) and rock properties (porosity. permeability). Reservoir models are validated by matching historical performance data (e.g., reservoir pressures, well production or injection rates). Geologic models are adjusted until they produce a history match, and model adjustments are focused on inputs that have the greatest geologic uncertainty. Flow simulation models are then used to optimize field development strategies and to forecast field performance under different development scenarios. (author)

Extracting maximum petrophysical and geological information from a limited reservoir database

Energy Technology Data Exchange (ETDEWEB)

Ali, M.; Chawathe, A.; Ouenes, A. [New Mexico Institute of Mining and Technology, Socorro, NM (United States)] [and others

1997-08-01

The characterization of old fields lacking sufficient core and log data is a challenging task. This paper describes a methodology that uses new and conventional tools to build a reliable reservoir model for the Sulimar Queen field. At the fine scale, permeability measured on a fine grid with a minipermeameter was used in conjunction with the petrographic data collected on multiple thin sections. The use of regression analysis and a newly developed fuzzy logic algorithm led to the identification of key petrographic elements which control permeability. At the log scale, old gamma ray logs were first rescaled/calibrated throughout the entire field for consistency and reliability using only four modem logs. Using data from one cored well and the rescaled gamma ray logs, correlations between core porosity, permeability, total water content and gamma ray were developed to complete the small scale characterization. At the reservoir scale, outcrop data and the rescaled gamma logs were used to define the reservoir structure over an area of ten square miles where only 36 wells were available. Given the structure, the rescaled gamma ray logs were used to build the reservoir volume by identifying the flow units and their continuity. Finally, history-matching results constrained to the primary production were used to estimate the dynamic reservoir properties such as relative permeabilities to complete the characterization. The obtained reservoir model was tested by forecasting the waterflood performance and which was in good agreement with the actual performance.

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.

Estimation of permeability and permeability anisotropy in horizontal wells through numerical simulation of mud filtrate invasion

Energy Technology Data Exchange (ETDEWEB)

Pereira, Nelson [PETROBRAS S.A., Rio de Janeiro, RJ (Brazil). Exploracao e Producao; Altman, Raphael; Rasmus, John; Oliveira, Jansen [Schlumberger Servicos de Petroleo Ltda., Rio de Janeiro, RJ (Brazil)

2008-07-01

This paper describes how permeability and permeability anisotropy is estimated in horizontal wells using LWD (logging-while-drilling) laterolog resistivity data. Laterolog-while-drilling resistivity passes of while-drilling and timelapse (while reaming) were used to capture the invasion process. Radial positions of water based mud invasion fronts were calculated from while-drilling and reaming resistivity data. The invasion process was then recreated by constructing forward models with a fully implicit, near-wellbore numerical simulation such that the invasion front at a given time was consistent with the position of the front predicted by resistivity inversions. The radial position of the invasion front was shown to be sensitive to formation permeability. The while-drilling environment provides a fertile scenario to investigate reservoir dynamic properties because mud cake integrity and growth is not fully developed which means that the position of the invasion front at a particular point in time is more sensitive to formation permeability. The estimation of dynamic formation properties in horizontal wells is of particular value in marginal fields and deep-water offshore developments where running wireline and obtaining core is not always feasible, and where the accuracy of reservoir models can reduce the risk in field development decisions. (author)

Tectonic controls on preservation of Middle Triassic Halfway reservoir facies, Peejay Field, northeastern British Columbia: a new hydrocarbon exploration model

Energy Technology Data Exchange (ETDEWEB)

Caplan, M. L. [British Columbia Univ., Vancouver, BC (Canada). Dept. of Geological Sciences; Moslow, T. F. [Calgary Univ., AB (Canada). Dept. of Geology and Geophysics

1997-12-01

The Peejay Field in northeastern British Columbia was chosen as the site of a detailed study to establish the paleogeography, geological history and genesis of reservoir facies of Middle Triassic strata. A total of 132 cores and well logs from 345 wells were examined to establish the depositional model, to identify the origin of all reservoir facies and to construct an exploration model to improve the prediction of reservoir facies. Results show that the Middle Triassic Halfway Formation of northeastern British Columbia is comprised of at least four west-southwest prograding paleoshorelines. The Lithofacies Succession One quartz-arenites paleoshore faces have less porosity and permeability and are laterally discontinuous. For these reasons shoreface facies have minimal reservoir quality. The tidal inlet fill successions were found to have the greatest observed porosity, permeability and lateral continuity in the Peejay Field. The geometry and orientation of these tidal inlet fill deposits are controlled by tectonic processes. It was suggested that the success of hydrocarbon exploration in this structurally complex area of northeastern British Columbia and west-central Alberta depends on further stratigraphic and sedimentological examination of Middle Triassic strata on a regional scale to obtain a complete understanding of the geological history of the area. 39 refs., 13 refs.

Predicting petrophysical properties by simultaneous inversion of seismic and reservoir engineering data

Science.gov (United States)

Mantilla, Andres Eduardo

physics and seismic characterization of the fluvial sandstones in the Cretaceous K2 Unit of the Apiay-Guatiquia Oil Field. First I study the relationship between petrophysical and seismic properties for the K2 Unit reservoir rocks, at the pore, well log, and field scales. Then, I apply the joint inversion methodology I propose to the estimation of porosity and permeability in the drainage area of one of the wells in this field.

Integrated 3D Reservoir/Fault Property Modelling Aided Well Planning and Improved Hydrocarbon Recovery in a Niger Delta Field

International Nuclear Information System (INIS)

Onyeagoro, U. O.; Ebong, U. E.; Nworie, E. A.

2002-01-01

The large and varied portfolio of assets managed by oil companies requires quick decision-making and the deployment of best in class technologies in asset management. Timely decision making and the application of the best technologies in reservoir management are however sometimes in conflict due to large time requirements of the latter.Optimizing the location of development wells is critical to account for variable fluid contact movements and pressure interference effects between wells, which can be significant because of the high permeability (Darcy range) of Niger Delta reservoirs. With relatively high drilling costs, the optimization of well locations necessitates a good realistic static and dynamic 3D reservoir description, especially in the recovery of remaining oil and oil rim type of reservoirs.A detailed 3D reservoir model with fault properties was constructed for a Niger delta producing field. This involved the integration of high quality 3D seismic, core, petrophysics, reservoir engineering, production and structural geology data to construct a realistic 3D reservoir/fault property model for the field. The key parameters considered during the construction of the internal architecture of the model were the vertical and horizontal reservoir heterogeneities-this controls the fluid flow within the reservoir. In the production realm, the fault thickness and fault permeabilities are factors that control the impedance of fluid flow across the fault-fault transmissibility. These key internal and external reservoir/structural variables were explicitly modeled in a 3D modeling software to produce different realizations and manage the uncertainties.The resulting 3D reservoir/fault property model was upscaled for simulation purpose such that grid blocks along the fault planes have realistic transmissibility multipliers of 0 to 1 attached to them. The model was also used in the well planner to optimize the positioning of a high angle deviated well that penetrated

Using laboratory flow experiments and reactive chemical transport modeling for designing waterflooding of the Agua Fria Reservoir, Poza Rica-Altamira Field, Mexico

Energy Technology Data Exchange (ETDEWEB)

Birkle, P.; Pruess, K.; Xu, T.; Figueroa, R.A. Hernandez; Lopez, M. Diaz; Lopez, E. Contreras

2008-10-01

Waterflooding for enhanced oil recovery requires that injected waters must be chemically compatible with connate reservoir waters, in order to avoid mineral dissolution-and-precipitation cycles that could seriously degrade formation permeability and injectivity. Formation plugging is a concern especially in reservoirs with a large content of carbonates, such as calcite and dolomite, as such minerals typically react rapidly with an aqueous phase, and have strongly temperature-dependent solubility. Clay swelling can also pose problems. During a preliminary waterflooding pilot project, the Poza Rica-Altamira oil field, bordering the Gulf coast in the eastern part of Mexico, experienced injectivity loss after five months of reinjection of formation waters into well AF-847 in 1999. Acidizing with HCl restored injectivity. We report on laboratory experiments and reactive chemistry modeling studies that were undertaken in preparation for long-term waterflooding at Agua Frma. Using analogous core plugs obtained from the same reservoir interval, laboratory coreflood experiments were conducted to examine sensitivity of mineral dissolution and precipitation effects to water composition. Native reservoir water, chemically altered waters, and distilled water were used, and temporal changes in core permeability, mineral abundances and aqueous concentrations of solutes were monitored. The experiments were simulated with the multi-phase, nonisothermal reactive transport code TOUGHREACT, and reasonable to good agreement was obtained for changes in solute concentrations. Clay swelling caused an additional impact on permeability behavior during coreflood experiments, whereas the modeled permeability depends exclusively on chemical processes. TOUGHREACT was then used for reservoir-scale simulation of injecting ambient-temperature water (30 C, 86 F) into a reservoir with initial temperature of 80 C (176 F). Untreated native reservoir water was found to cause serious porosity and

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

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.

Upscaling of permeability field of fractured rock system: Numerical examples

KAUST Repository

Bao, K.; Salama, Amgad; Sun, S.

2012-01-01

When the permeability field of a given porous medium domain is heterogeneous by the existence of randomly distributed fractures such that numerical investigation becomes cumbersome, another level of upscaling may be required. That is such complex permeability field could be relaxed (i.e., smoothed) by constructing an effective permeability field. The effective permeability field is an approximation to the real permeability field that preserves certain quantities and provides an overall acceptable description of the flow field. In this work, the effective permeability for a fractured rock system is obtained for different coarsening scenarios starting from very coarse mesh all the way towards the fine mesh simulation. In all these scenarios, the effective permeability as well as the pressure at each cell is obtained. The total flux at the exit boundary is calculated in all these cases, and very good agreement is obtained.

Reservoir engineering assessment of Dubti geothermal field, Northern Tendaho Rift, Ethiopia

Energy Technology Data Exchange (ETDEWEB)

Battistelli, A.; Ferragina, C. [Aquater S.p.A. (ENI Group), San Lorenzo in Campo (Italy); Yiheyis, A.; Abatneh, W. [Ethiopian Institute of Geological Surveys, Addis Ababa (Ethiopia); Calore, C. [International Institute for Geothermal Research, Pisa (Italy)

2002-06-01

Following on from surface exploration surveys performed during the 1970s and early 1980s, exploration drilling was carried out in the Tendaho Rift, in Central Afar (Ethiopia), from October 1993 to June 1995. Three deep and one shallow well were drilled in the central part of the Northern Tendaho Rift to verify the existence of a geothermal reservoir and its possible utilisation for electric power generation. The project was jointly financed by the Ethiopian Ministry of Mines and Energy and the Italian Ministry for Foreign Affairs. Project activities were performed by the Ethiopian Institute of Geological Surveys and Aquater SpA. The main reservoir engineering data discussed in this paper were collected during drilling and testing of the above four wells, three of which are located inside the Dubti Cotton Plantation, in which a promising hydrothermal area was identified by surface exploration surveys. Drilling confirmed the existence of a liquid-dominated shallow reservoir inside the Dubti Plantation, characterised by a boiling -point-for-depth temperature distribution down to about 500 m depth. The main permeable zones in the Sedimentary Sequence, which is made up of lacustrine deposits, are located in correspondence to basalt lava flow interlayerings, or at the contact between volcanic and sedimentary rocks. At depth, the basaltic lava flows that characterise the Afar Stratoid Series seem to have low permeability, with the exception of fractured zones associated with sub-vertical faults. Two different upflows of geothermal fluids have been inferred: one flow connected to the Dubti fault feeds the shallow reservoir crossed by wells TD-2 and TD-4, where a maximum temperature of 245{sup o}C was recorded; the second flow seems to be connected with a fault located east of well TD-1, where the maximum recorded temperature was 270{sup o}C. A schematic conceptual model of the Dubti hydrothermal area, as derived from reservoir engineering studies integrated with geological

Seismic Response of Deep Hydrocarbon Bearing Reservoirs: examples from Oso Field and implications for Future Opportunities

International Nuclear Information System (INIS)

Oluwasusi, A. B.; Hussey, V.; Goulding, F. J.

2002-01-01

The Oso Field (OML 70) produces approximately 100 TBD of condensate from Miocene age shelfal sand reservoirs at approximately 10,000 feet below sea level. The field was discovered in 1967 while testing a deeply buried fault closure. Reservoirs are normally pressured, exceed 1 Darcy in permeability and range from 50 to 600 feet in thickness.There are seismic amplitudes associated with the shallower reservoirs on the existing conventional 3D dataset; however there are no anomalies associated with the deeper, condensate accumulations.The paper explores the physical rock and fluid properties associated with the Oso reservoirs and the resulting seismic responses. Modelled results have been calibrated with the actual seismic signatures for the water and hydrocarbon bearing zones. Results indicate that the deeper reservoirs exhibit a classic Class II AVG seismic response and that the use of longer offset and angle stack data can help predict the occurrence of these types of reservoirs. Examples of similar accumulations will be shared.Mobil Producing Nigeria is conducting a full reprocessing effort of the existing 3D dataset over the Joint Venture acreage with a goal of identifying and exploiting additional accumulations with Class II AVG seismic response. Preliminary results of the reprocessing over known accumulations will be presented

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.

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

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.

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

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.

Diagenesis and reservoir quality of Bhuban sandstones (Neogene), Titas Gas Field, Bengal Basin, Bangladesh

Science.gov (United States)

Aminul Islam, M.

2009-06-01

This study deals with the diagenesis and reservoir quality of sandstones of the Bhuban Formation located at the Titas Gas Field of Bengal Basin. Petrographic study including XRD, CL, SEM and BSE image analysis and quantitative determination of reservoir properties were carried out for this study. The sandstones are fine to medium-grained, moderately well to well sorted subfeldspathic arenites with subordinate feldspathic and lithic arenites. The diagenetic processes include clay infiltration, compaction and cementation (quartz overgrowth, chlorite, kaolinite, calcite and minor amount of pyrite, dolomite and K-feldspar overgrowth). Quartz is the dominant pore occluding cement and generally occurred as small euhedral crystals, locally as large pyramidal crystals in the primary pores. Pressure solution derived from grain contact is the main contributor of quartz overgrowths. Chlorite occurs as pore-lining and pore filling cement. In some cases, chlorite helps to retain porosity by preventing quartz overgrowth. In some restricted depth interval, pore-occlusion by calcite cement is very much intense. Kaolinite locally developed as vermiform and accelerated the minor porosity loss due to pore-occlusion. Kaolinite/chlorite enhances ineffective microporosity. Kaolinite is a by-product of feldspar leaching in the presence of acidic fluid produced during the maturation of organic matter in the adjacent Miocene or deeper Oligocene source rocks. The relation between diagenesis and reservoir quality is as follows: the initial porosity was decreased by compaction and cementation and then increased by leaching of the metastable grains and dissolution of cement. Good quality reservoir rocks were deposited in fluvial environment and hence quality of reservoir rocks is also environment selective. Porosity and permeability data exhibit good inverse correlation with cement. However, some data points indicate multiple controls on permeability. Reservoir quality is thus controlled by

Heterogeneous porous media permeability field characterization from fluid displacement data; Integration de donnees de deplacements de fluides dans la caracterisation de milieux poreux heterogenes

Energy Technology Data Exchange (ETDEWEB)

Kretz, V.

2002-11-01

The prediction of oil recovery or pollutant dispersion requires an accurate knowledge of the permeability field distribution. Available data are usually measurements in well bores, and, since a few years, 4D-seismic data (seismic mappings repeated in time). Such measurements allow to evaluate fluids displacements fronts evolution. The purpose of the thesis is to evaluate the possibility to determinate permeability fields from fluid displacement measurements in heterogeneous porous media. At the laboratory scale, experimental studies are made on a model and on numerical simulations. The system uses blocks of granular materials whose individual geometries and permeabilities are controlled. The fluids displacements are detected with an acoustical. The key parameters of the study are the size and spatial correlation of the permeability heterogeneity distribution, and the influence of viscosity and gravity contrasts between the injected ant displaced fluid. Then the inverse problem - evaluating the permeability field from concentration fronts evolution - is approached. At the reservoir scale, the work will mainly be focused on the integration of 4D-seismic data into inversion programs on a 3D synthetic case. A particular importance will be given to the calculation of gradients, in order to obtain a complementary information about the sensitivity of data. The information provided by 4D-seismic data consists in maps showing the vertical average of oil saturation or the presence of gas. The purpose is to integrate this qualitative information in the inversion process and to evaluate the impact on the reservoir characterization. Comparative studies - with or without 4D-seismic data - will be realized on a synthetic case. (author)

Changes in permeability caused by transient stresses: field observations, experiments, and mechanisms

Science.gov (United States)

Manga, Michael; Beresnev, Igor; Brodsky, Emily E.; Elkhoury, Jean E.; Elsworth, Derek; Ingebritsen, Steve E.; Mays, David C.; Wang, Chi-Yuen

2012-01-01

Oscillations in stress, such as those created by earthquakes, can increase permeability and fluid mobility in geologic media. In natural systems, strain amplitudes as small as 10–6 can increase discharge in streams and springs, change the water level in wells, and enhance production from petroleum reservoirs. Enhanced permeability typically recovers to prestimulated values over a period of months to years. Mechanisms that can change permeability at such small stresses include unblocking pores, either by breaking up permeability-limiting colloidal deposits or by mobilizing droplets and bubbles trapped in pores by capillary forces. The recovery time over which permeability returns to the prestimulated value is governed by the time to reblock pores, or for geochemical processes to seal pores. Monitoring permeability in geothermal systems where there is abundant seismicity, and the response of flow to local and regional earthquakes, would help test some of the proposed mechanisms and identify controls on permeability and its evolution.

Are Geotehrmal Reservoirs Stressed Out?

Science.gov (United States)

Davatzes, N. C.; Laboso, R. C.; Layland-Bachmann, C. E.; Feigl, K. L.; Foxall, W.; Tabrez, A. R.; Mellors, R. J.; Templeton, D. C.; Akerley, J.

2017-12-01

Crustal permeability can be strongly influenced by developing connected networks of open fractures. However, the detailed evolution of a fracture network, its extent, and the persistence of fracture porosity are difficult to analyze. Even in fault-hosted geothermal systems, where heat is brought to the surface from depth along a fault, hydrothermal flow is heterogeneously distributed. This is presumably due to variations in fracture density, connectivity, and attitude, as well as variations in fracture permeability caused by sealing of fractures by precipitated cements or compaction. At the Brady Geothermal field in Nevada, we test the relationship between the modeled local stress state perturbed by dislocations representing fault slip or volume changes in the geothermal reservoir inferred from surface deformation measured by InSAR and the location of successful geothermal wells, hydrothermal activity, and seismicity. We postulate that permeability is favored in volumes that experience positive Coulomb stress changes and reduced compression, which together promote high densities of dilatant fractures. Conversely, permeability can be inhibited in locations where Coulomb stress is reduced, compression promotes compaction, or where the faults are poorly oriented in the stress field and consequently slip infrequently. Over geologic time scales spanning the development of the fault system, these local stress states are strongly influenced by the geometry of the fault network relative to the remote stress driving slip. At shorter time scales, changes in fluid pressure within the fracture network constituting the reservoir cause elastic dilations and contractions. We integrate: (1) direct observations of stress state and fractures in boreholes and the mapped geometry of the fault network; (2) evidence of permeability from surface hydrothermal features, production/injection wells and surface deformations related to pumping history; and (3) seismicity to test the

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

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

A fully-coupled discontinuous Galerkin spectral element method for two-phase flow in petroleum reservoirs

Science.gov (United States)

Taneja, Ankur; Higdon, Jonathan

2018-01-01

A high-order spectral element discontinuous Galerkin method is presented for simulating immiscible two-phase flow in petroleum reservoirs. The governing equations involve a coupled system of strongly nonlinear partial differential equations for the pressure and fluid saturation in the reservoir. A fully implicit method is used with a high-order accurate time integration using an implicit Rosenbrock method. Numerical tests give the first demonstration of high order hp spatial convergence results for multiphase flow in petroleum reservoirs with industry standard relative permeability models. High order convergence is shown formally for spectral elements with up to 8th order polynomials for both homogeneous and heterogeneous permeability fields. Numerical results are presented for multiphase fluid flow in heterogeneous reservoirs with complex geometric or geologic features using up to 11th order polynomials. Robust, stable simulations are presented for heterogeneous geologic features, including globally heterogeneous permeability fields, anisotropic permeability tensors, broad regions of low-permeability, high-permeability channels, thin shale barriers and thin high-permeability fractures. A major result of this paper is the demonstration that the resolution of the high order spectral element method may be exploited to achieve accurate results utilizing a simple cartesian mesh for non-conforming geological features. Eliminating the need to mesh to the boundaries of geological features greatly simplifies the workflow for petroleum engineers testing multiple scenarios in the face of uncertainty in the subsurface geology.

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

carbonate reservoirs of widely varying moldic pore systems that represent the major of reservoirs in Kansas and are important nationally and worldwide. A goal of the project is to measure wettability, using representative oils from Kansas fields, on a wide range of moldic-porosity lithofacies that are representative of Kansas and midcontinent shallow-shelf carbonate reservoirs. This investigation will discern the relative influence of wetting and pore architecture. In the midcontinent, reservoir water saturations are frequently greater than 'irreducible' because many reservoirs are largely in the capillary transition zone. This can change the imbibition oil-water relative permeability relations. Ignoring wettability and transition-zone relative permeabilities in reservoir modeling can lead to over- and under-prediction of oil recovery and recovery rates, and less effective improved recovery management. A goal of this project is to measure drainage and imbibition oil-water relative permeabilities for a large representative range of lithofacies at differ ent initial water saturations to obtain relations that can be applied everywhere in the reservoir. The practical importance of these relative permeability and wettability models will be demonstrated by using reservoir simulation studies on theoretical/generic and actual reservoir architectures. The project further seeks to evaluate how input of these new models affects reservoir simulation results at varying scales. A principal goal is to obtain data that will allow us to create models that will show how to accurately simulate flow in the shallow-structure, complex carbonate reservoirs that lie in the transition zone. Tasks involved to meet the project objectives include collection and consolidation of available data into a publicly accessible relational digital database and collection of oil and rock samples from carbonate fields around the state (Task 1). Basic properties of these rocks and oils will be measured

Pennsylvanian carbonate buildups, Paradox basin: Increasing reserves in heterogeneous, shallow-shelf reservoirs

Science.gov (United States)

Montgomery, S.L.; Chidsey, T.C.; Eby, D.E.; Lorenz, D.M.; Culham, W.E.

1999-01-01

Productive carbonate buildups of Pennsylvanian age in the southern Paradox basin, Utah, contain up to 200 million bbl remaining oil potentially recoverable by enhanced recovery methods. These buildups comprise over 100 satellite fields to the giant Greater Aneth field, where secondary recovery operations thus far have been concentrated. Several types of satellite buildups exist and produce oil from the Desert Creek zone of the Paradox Formation. Many of the relevant fields have undergone early abandonment; wells in Desert Creek carbonate mounds commonly produce at very high initial rates (>1000 bbl/day) and then suffer precipitous declines. An important new study focused on the detailed characterization of five separate reservoirs has resulted in significant information relevant to their future redevelopment. Completed assessment of Anasazi field suggests that phylloid algal mounds, the major productive buildup type in this area, consist of ten separate lithotypes and can be described in terms of a two-level reservoir system with an underlying high-permeability mound-core interval overlain by a lower permeability but volumetrically larger supramound (mound capping) interval. Reservoir simulations and related performance predictions indicate that CO2 flooding of these reservoirs should have considerable success in recovering remaining oil reserves.Productive carbonate buildups of Pennsylvanian age in the southern Paradox basin, Utah, contain up to 200 million bbl remaining oil potentially recoverable by enhanced recovery methods. These buildups comprise over 100 satellite fields to the giant Greater Aneth field, where secondary recovery operations thus far have been concentrated. Several types of satellite buildups exist and produce oil from the Desert Creek zone of the Paradox Formation. Many of the relevant fields have undergone early abandonment; wells in Desert Creek carbonate mounds commonly produce at very high initial rates (>1000 bbl/day) and then suffer

An Integrated Rock Typing Approach for Unraveling the Reservoir Heterogeneity of Tight Sands in the Whicher Range Field of Perth Basin, Western Australia

DEFF Research Database (Denmark)

Ilkhchi, Rahim Kadkhodaie; Rezaee, Reza; Harami, Reza Moussavi

2014-01-01

Tight gas sands in Whicher Range Field of Perth Basin show large heterogeneity in reservoir characteristics and production behavior related to depositional and diagenetic features. Diagenetic events (compaction and cementation) have severely affected the pore system. In order to investigate...... the petrophysical characteristics, reservoir sandstone facies were correlated with core porosity and permeability and their equivalent well log responses to describe hydraulic flow units and electrofacies, respectively. Thus, very tight, tight, and sub-tight sands were differentiated. To reveal the relationship...... between pore system properties and depositional and diagenetic characteristics in each sand type, reservoir rock types were extracted. The identified reservoir rock types are in fact a reflection of internal reservoir heterogeneity related to pore system properties. All reservoir rock types...

Field data provide estimates of effective permeability, fracture spacing, well drainage area and incremental production in gas shales

KAUST Repository

Eftekhari, Behzad

2018-05-23

About half of US natural gas comes from gas shales. It is valuable to study field production well by well. We present a field data-driven solution for long-term shale gas production from a horizontal, hydrofractured well far from other wells and reservoir boundaries. Our approach is a hybrid between an unstructured big-data approach and physics-based models. We extend a previous two-parameter scaling theory of shale gas production by adding a third parameter that incorporates gas inflow from the external unstimulated reservoir. This allows us to estimate for the first time the effective permeability of the unstimulated shale and the spacing of fractures in the stimulated region. From an analysis of wells in the Barnett shale, we find that on average stimulation fractures are spaced every 20 m, and the effective permeability of the unstimulated region is 100 nanodarcy. We estimate that over 30 years on production the Barnett wells will produce on average about 20% more gas because of inflow from the outside of the stimulated volume. There is a clear tradeoff between production rate and ultimate recovery in shale gas development. In particular, our work has strong implications for well spacing in infill drilling programs.

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

A novel methodology improves reservoir characterization models using geologic fuzzy variables

Energy Technology Data Exchange (ETDEWEB)

Soto B, Rodolfo [DIGITOIL, Maracaibo (Venezuela); Soto O, David A. [Texas A and M University, College Station, TX (United States)

2004-07-01

One of the research projects carried out in Cusiana field to explain its rapid decline during the last years was to get better permeability models. The reservoir of this field has a complex layered system that it is not easy to model using conventional methods. The new technique included the development of porosity and permeability maps from cored wells following the same trend of the sand depositions for each facie or layer according to the sedimentary facie and the depositional system models. Then, we used fuzzy logic to reproduce those maps in three dimensions as geologic fuzzy variables. After multivariate statistical and factor analyses, we found independence and a good correlation coefficient between the geologic fuzzy variables and core permeability and porosity. This means, the geologic fuzzy variable could explain the fabric, the grain size and the pore geometry of the reservoir rock trough the field. Finally, we developed a neural network permeability model using porosity, gamma ray and the geologic fuzzy variable as input variables. This model has a cross-correlation coefficient of 0.873 and average absolute error of 33% compared with the actual model with a correlation coefficient of 0.511 and absolute error greater than 250%. We tested different methodologies, but this new one showed dramatically be a promiser way to get better permeability models. The use of the models have had a high impact in the explanation of well performance and workovers, and reservoir simulation models. (author)

Numerical investigation of electricity generation potential from fractured granite reservoir through a single vertical well at Yangbajing geothermal field

International Nuclear Information System (INIS)

Zeng, Yu-Chao; Zhan, Jie-Min; Wu, Neng-You; Luo, Ying-Ying; Cai, Wen-Hao

2016-01-01

Deep geological exploration indicates that there is a high-temperature fractured granite reservoir at depth of 950 ~ 1350 m in well ZK4001 in the north of Yangbajing geothermal field, with an average temperature of 248 °C and a pressure within 8.01 ~ 11.57 MPa; in this well there mainly produces liquid and steam two-phase flow. In this work we numerically investigated the electricity generation potential from the fractured granite reservoir through a single vertical well, analyzed the process and mechanism of the two-phase flow, and evaluated main factors affecting the heat production and electricity generation. The results show that under the reference conditions the system attains a pump power of 0.02 ~ 0.16 MW, an electrical power of 2.71 ~ 2.69 MW, and an energy efficiency of 68.06 ~ 16.34, showing favorable electricity generation performance. During the production period, the bottomhole production pressure gradually decreases, and this makes the pump power increasing and the energy efficiency decreasing. When the bottomhole pressure is lower than the saturated vapor pressure, the liquid water begins to evaporate and the bottomhole wellbore begins to produce the mixture of liquid and steam. Main factors affecting the performance are reservoir porosity, permeability and fluid production rate. Higher reservoir porosity or higher permeability or lower fluid production rate will increase the bottomehole pressure, decrease the pump power and improve the energy efficiency. - Highlights: • We established a numerical model of a single vertical well heat mining system. • Desirable electricity production performance can be obtained under suitable conditions. • The system attains an electric power of 2.71 ~ 2.69 MW with an efficiency of about 68.06 ~ 16.34. • Electric power mainly depends on the reservoir porosity and water production rate. • Higher permeability within a certain range is favorable for electricity generation.

Automated extraction of faults and porous reservoir bodies. Examples from the Vallhall Field

Energy Technology Data Exchange (ETDEWEB)

Barkved, Olav Inge; Whitman, Doug; Kunz, Tim

1998-12-31

The Norwegian Vahall field is located 250 km South-West of Stavanger. The production is primarily from the highly porous and fractured chalk, the Tor formation. Fractures, evidently play a significant role in enhancing flow properties as well as production rates, are significantly higher than expected from matrix permeability alone. The fractures are primarily tectonically induced and related to faulting. Syn-depositional faulting is believed to be a controlling factor on reservoir thickness variations observed across the field. Due to the low acoustic contrast and weak appearance of the highly porous chalk, direct evidence of faulting in well bore logs is limited. The seismic data quality in the most central area of the field is very poor due to tertiary gas charging, but in the flank area of the field, the quality is excellent. 1 ref., 5 figs.

Numerical investigation of electricity generation potential from fractured granite reservoir by water circulating through three horizontal wells at Yangbajing geothermal field

International Nuclear Information System (INIS)

Zeng, Yuchao; Zhan, Jiemin; Wu, Nengyou; Luo, Yingying; Cai, Wenhao

2016-01-01

Highlights: • A numerical model of the 950–1350 m fractured granite reservoir through horizontal wells is established. • Desirable electricity production performance can be obtained under suitable conditions. • The system attains an electric power of 26.9–24.3 MW with an efficiency of about 50.10–22.39. • Electric power mainly depends on water production rate and injection temperature. • Higher permeability within a certain range is favorable for electricity generation. - Abstract: Deep geological exploration indicates that there is a high-temperature fractured granite reservoir at depth of 950–1350 m in well ZK4001 in the north of Yangbajing geothermal field, with an average temperature of 248 °C and a pressure within 8.01–11.57 MPa. In this work, we evaluated electricity generation potential from this fractured granite reservoir by water circulating through three horizontal wells, and analyzed main factors affecting the performance and efficiency through numerical simulation. The results show that in the reference case the system attains a production temperature of 248.0–235.7 °C, an electrical power of 26.9–24.3 MW, an injection pressure of 10.48–12.94 MPa, a reservoir impedance of 0.07–0.10 MPa/(kg/s), a pump power of 0.54–1.08 MW and an energy efficiency of 50.10–22.39 during a period of 20 years, displaying favorable production performance. Main factors affecting the production performance and efficiency are reservoir permeability, water production rate and injection temperature; within certain ranges increasing the reservoir permeability or adopting more reasonable water production rate or injection temperature will obviously improve the system production performance.

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.

Permeability enhancement by shock cooling

Science.gov (United States)

Griffiths, Luke; Heap, Michael; Reuschlé, Thierry; Baud, Patrick; Schmittbuhl, Jean

2015-04-01

The permeability of an efficient reservoir, e.g. a geothermal reservoir, should be sufficient to permit the circulation of fluids. Generally speaking, permeability decreases over the life cycle of the geothermal system. As a result, is usually necessary to artificially maintain and enhance the natural permeability of these systems. One of the methods of enhancement -- studied here -- is thermal stimulation (injecting cold water at low pressure). This goal of this method is to encourage new thermal cracks within the reservoir host rocks, thereby increasing reservoir permeability. To investigate the development of thermal microcracking in the laboratory we selected two granites: a fine-grained (Garibaldi Grey granite, grain size = 0.5 mm) and a course-grained granite (Lanhelin granite, grain size = 2 mm). Both granites have an initial porosity of about 1%. Our samples were heated to a range of temperatures (100-1000 °C) and were either cooled slowly (1 °C/min) or shock cooled (100 °C/s). A systematic microstructural (2D crack area density, using standard stereological techniques, and 3D BET specific surface area measurements) and rock physical property (porosity, P-wave velocity, uniaxial compressive strength, and permeability) analysis was undertaken to understand the influence of slow and shock cooling on our reservoir granites. Microstructurally, we observe that the 2D crack surface area per unit volume and the specific surface area increase as a result of thermal stressing, and, for the same maximum temperature, crack surface area is higher in the shock cooled samples. This observation is echoed by our rock physical property measurements: we see greater changes for the shock cooled samples. We can conclude that shock cooling is an extremely efficient method of generating thermal microcracks and modifying rock physical properties. Our study highlights that thermal treatments are likely to be an efficient method for the "matrix" permeability enhancement of

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.

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.

Three-dimensional numerical reservoir simulation of the EGS Demonstration Project at The Geysers geothermal field

Science.gov (United States)

Borgia, Andrea; Rutqvist, Jonny; Oldenburg, Curt M.; Hutchings, Lawrence; Garcia, Julio; Walters, Mark; Hartline, Craig; Jeanne, Pierre; Dobson, Patrick; Boyle, Katie

2013-04-01

The Enhanced Geothermal System (EGS) Demonstration Project, currently underway at the Northwest Geysers, California, aims to demonstrate the feasibility of stimulating a deep high-temperature reservoir (up to 400 °C) through water injection over a 2-year period. On October 6, 2011, injection of 25 l/s started from the Prati 32 well at a depth interval of 1850-2699 m below sea level. After a period of almost 2 months, the injection rate was raised to 63 l/s. The flow rate was then decreased to 44 l/s after an additional 3.5 months and maintained at 25 l/s up to August 20, 2012. Significant well-head pressure changes were recorded at Prati State 31 well, which is separated from Prati 32 by about 500 m at reservoir level. More subdued pressure increases occur at greater distances. The water injection caused induced seismicity in the reservoir in the vicinity of the well. Microseismic monitoring and interpretation shows that the cloud of seismic events is mainly located in the granitic intrusion below the injection zone, forming a cluster elongated SSE-NNW (azimuth 170°) that dips steeply to the west. In general, the magnitude of the events increases with depth and the hypocenter depth increases with time. This seismic cloud is hypothesized to correlate with enhanced permeability in the high-temperature reservoir and its variation with time. Based on the existing borehole data, we use the GMS™ GUI to construct a realistic three-dimensional (3D) geologic model of the Northwest Geysers geothermal field. This model includes, from the top down, a low permeability graywacke layer that forms the caprock for the reservoir, an isothermal steam zone (known as the normal temperature reservoir) within metagraywacke, a hornfels zone (where the high-temperature reservoir is located), and a felsite layer that is assumed to extend downward to the magmatic heat source. We then map this model onto a rectangular grid for use with the TOUGH2 multiphase, multicomponent, non

Unconventional Tight Reservoirs Characterization with Nuclear Magnetic Resonance

Science.gov (United States)

Santiago, C. J. S.; Solatpour, R.; Kantzas, A.

2017-12-01

The increase in tight reservoir exploitation projects causes producing many papers each year on new, modern, and modified methods and techniques on estimating characteristics of these reservoirs. The most ambiguous of all basic reservoir property estimations deals with permeability. One of the logging methods that is advertised to predict permeability but is always met by skepticism is Nuclear Magnetic Resonance (NMR). The ability of NMR to differentiate between bound and movable fluids and providing porosity increased the capability of NMR as a permeability prediction technique. This leads to a multitude of publications and the motivation of a review paper on this subject by Babadagli et al. (2002). The first part of this presentation is dedicated to an extensive review of the existing correlation models for NMR based estimates of tight reservoir permeability to update this topic. On the second part, the collected literature information is used to analyze new experimental data. The data are collected from tight reservoirs from Canada, the Middle East, and China. A case study is created to apply NMR measurement in the prediction of reservoir characterization parameters such as porosity, permeability, cut-offs, irreducible saturations etc. Moreover, permeability correlations are utilized to predict permeability. NMR experiments were conducted on water saturated cores. NMR T2 relaxation times were measured. NMR porosity, the geometric mean relaxation time (T2gm), Irreducible Bulk Volume (BVI), and Movable Bulk Volume (BVM) were calculated. The correlation coefficients were computed based on multiple regression analysis. Results are cross plots of NMR permeability versus the independently measured Klinkenberg corrected permeability. More complicated equations are discussed. Error analysis of models is presented and compared. This presentation is beneficial in understanding existing tight reservoir permeability models. The results can be used as a guide for choosing

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.

Influence of demagnetizing field on the permeability of soft magnetic composites

International Nuclear Information System (INIS)

Lin, G.Q.; Li, Z.W.; Chen, Linfeng; Wu, Y.P.; Ong, C.K.

2006-01-01

The influence of demagnetizing field on the effective permeability of magnetic composites has been investigated. A theoretical expression of the effective permeability has been obtained and discussed according to four typical composites with spheres, needles, flakes, and aligned prolate ellipsoidal particles. The results indicate that the demagnetizing field within the particles can reduce the effective permeability significantly. In order to increase the effective permeability, it is necessary to decrease the demagnetizing field within the particles. A linear relationship between effective permeability and volume fraction is also observed for composites filled with spherical particles at low volume fraction

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.

Integrated Approach to Drilling Project in Unconventional Reservoir Using Reservoir Simulation

Science.gov (United States)

Stopa, Jerzy; Wiśniowski, Rafał; Wojnarowski, Paweł; Janiga, Damian; Skrzypaszek, Krzysztof

2018-03-01

Accumulation and flow mechanisms in unconventional reservoir are different compared to conventional. This requires a special approach of field management with drilling and stimulation treatments as major factor for further production. Integrated approach of unconventional reservoir production optimization assumes coupling drilling project with full scale reservoir simulation for determine best well placement, well length, fracturing treatment design and mid-length distance between wells. Full scale reservoir simulation model emulate a part of polish shale - gas field. The aim of this paper is to establish influence of technical factor for gas production from shale gas field. Due to low reservoir permeability, stimulation treatment should be direct towards maximizing the hydraulic contact. On the basis of production scenarios, 15 stages hydraulic fracturing allows boost gas production over 1.5 times compared to 8 stages. Due to the possible interference of the wells, it is necessary to determine the distance between the horizontal parts of the wells trajectories. In order to determine the distance between the wells allowing to maximize recovery factor of resources in the stimulated zone, a numerical algorithm based on a dynamic model was developed and implemented. Numerical testing and comparative study show that the most favourable arrangement assumes a minimum allowable distance between the wells. This is related to the volume ratio of the drainage zone to the total volume of the stimulated zone.

Comparative field permeability measurement of permeable pavements using ASTM C1701 and NCAT permeameter methods.

Science.gov (United States)

Li, Hui; Kayhanian, Masoud; Harvey, John T

2013-03-30

Fully permeable pavement is gradually gaining support as an alternative best management practice (BMP) for stormwater runoff management. As the use of these pavements increases, a definitive test method is needed to measure hydraulic performance and to evaluate clogging, both for performance studies and for assessment of permeability for construction quality assurance and maintenance needs assessment. Two of the most commonly used permeability measurement tests for porous asphalt and pervious concrete are the National Center for Asphalt Technology (NCAT) permeameter and ASTM C1701, respectively. This study was undertaken to compare measured values for both methods in the field on a variety of permeable pavements used in current practice. The field measurements were performed using six experimental section designs with different permeable pavement surface types including pervious concrete, porous asphalt and permeable interlocking concrete pavers. Multiple measurements were performed at five locations on each pavement test section. The results showed that: (i) silicone gel is a superior sealing material to prevent water leakage compared with conventional plumbing putty; (ii) both methods (NCAT and ASTM) can effectively be used to measure the permeability of all pavement types and the surface material type will not impact the measurement precision; (iii) the permeability values measured with the ASTM method were 50-90% (75% on average) lower than those measured with the NCAT method; (iv) the larger permeameter cylinder diameter used in the ASTM method improved the reliability and reduced the variability of the measured permeability. Copyright © 2013 Elsevier Ltd. All rights reserved.

Numerical Simulation of Natural Gas Flow in Anisotropic Shale Reservoirs

KAUST Repository

Negara, Ardiansyah

2015-11-09

Shale gas resources have received great attention in the last decade due to the decline of the conventional gas resources. Unlike conventional gas reservoirs, the gas flow in shale formations involves complex processes with many mechanisms such as Knudsen diffusion, slip flow (Klinkenberg effect), gas adsorption and desorption, strong rock-fluid interaction, etc. Shale formations are characterized by the tiny porosity and extremely low-permeability such that the Darcy equation may no longer be valid. Therefore, the Darcy equation needs to be revised through the permeability factor by introducing the apparent permeability. With respect to the rock formations, several studies have shown the existence of anisotropy in shale reservoirs, which is an essential feature that has been established as a consequence of the different geological processes over long period of time. Anisotropy of hydraulic properties of subsurface rock formations plays a significant role in dictating the direction of fluid flow. The direction of fluid flow is not only dependent on the direction of pressure gradient, but it also depends on the principal directions of anisotropy. Therefore, it is very important to take into consideration anisotropy when modeling gas flow in shale reservoirs. In this work, the gas flow mechanisms as mentioned earlier together with anisotropy are incorporated into the dual-porosity dual-permeability model through the full-tensor apparent permeability. We employ the multipoint flux approximation (MPFA) method to handle the full-tensor apparent permeability. We combine MPFA method with the experimenting pressure field approach, i.e., a newly developed technique that enables us to solve the global problem by breaking it into a multitude of local problems. This approach generates a set of predefined pressure fields in the solution domain in such a way that the undetermined coefficients are calculated from these pressure fields. In other words, the matrix of coefficients

Numerical Simulation of Natural Gas Flow in Anisotropic Shale Reservoirs

KAUST Repository

Negara, Ardiansyah; Salama, Amgad; Sun, Shuyu; Elgassier, Mokhtar; Wu, Yu-Shu

2015-01-01

Shale gas resources have received great attention in the last decade due to the decline of the conventional gas resources. Unlike conventional gas reservoirs, the gas flow in shale formations involves complex processes with many mechanisms such as Knudsen diffusion, slip flow (Klinkenberg effect), gas adsorption and desorption, strong rock-fluid interaction, etc. Shale formations are characterized by the tiny porosity and extremely low-permeability such that the Darcy equation may no longer be valid. Therefore, the Darcy equation needs to be revised through the permeability factor by introducing the apparent permeability. With respect to the rock formations, several studies have shown the existence of anisotropy in shale reservoirs, which is an essential feature that has been established as a consequence of the different geological processes over long period of time. Anisotropy of hydraulic properties of subsurface rock formations plays a significant role in dictating the direction of fluid flow. The direction of fluid flow is not only dependent on the direction of pressure gradient, but it also depends on the principal directions of anisotropy. Therefore, it is very important to take into consideration anisotropy when modeling gas flow in shale reservoirs. In this work, the gas flow mechanisms as mentioned earlier together with anisotropy are incorporated into the dual-porosity dual-permeability model through the full-tensor apparent permeability. We employ the multipoint flux approximation (MPFA) method to handle the full-tensor apparent permeability. We combine MPFA method with the experimenting pressure field approach, i.e., a newly developed technique that enables us to solve the global problem by breaking it into a multitude of local problems. This approach generates a set of predefined pressure fields in the solution domain in such a way that the undetermined coefficients are calculated from these pressure fields. In other words, the matrix of coefficients

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.

A review on hydraulic fracturing of unconventional reservoir

Directory of Open Access Journals (Sweden)

Quanshu Li

2015-03-01

Full Text Available Hydraulic fracturing is widely accepted and applied to improve the gas recovery in unconventional reservoirs. Unconventional reservoirs to be addressed here are with very low permeability, complicated geological settings and in-situ stress field etc. All of these make the hydraulic fracturing process a challenging task. In order to effectively and economically recover gas from such reservoirs, the initiation and propagation of hydraulic fracturing in the heterogeneous fractured/porous media under such complicated conditions should be mastered. In this paper, some issues related to hydraulic fracturing have been reviewed, including the experimental study, field study and numerical simulation. Finally the existing problems that need to be solved on the subject of hydraulic fracturing have been proposed.

Application of Advanced Reservoir Characterization, Simulation, and Production Optimization Strategies to Maximize Recovery in Slope and Basin Clastic Reservoirs, West Texas (Delaware Basin)

Energy Technology Data Exchange (ETDEWEB)

Dutton, S.P.; Flanders, W.A.; Guzman, J.I.; Zirczy, H.

1999-06-08

The objective of this Class III project is to demonstrate that detailed reservoir characterization of slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost-effective way to recover a higher percentage of the original oil in place through geologically based field development. This year the project focused on reservoir characterization of the East Ford unit, a representative Delaware Mountain Group field that produces from the upper Bell Canyon Formation (Ramsey Sandstone). The field, discovered in 1960, is operated by Orla Petco, Inc., as the East Ford unit; it contained an estimated 19.8 million barrels (MMbbl) of original oil in place. Petrophysical characterization of the East Ford unit was accomplished by integrating core and log data and quantifying petrophysical properties from wireline logs. Most methods of petrophysical analysis that had been developed during an earlier study of the Ford Geraldine unit were successfully transferred to the East Ford unit. The approach that was used to interpret water saturation from resistivity logs, however, had to be modified because in some East Ford wells the log-calculated water saturation was too high and inconsistent with observations made during the actual production. Log-porosity to core-porosity transforms and core-porosity to core-permeability transforms were derived from the East Ford reservoir. The petrophysical data were used to map porosity, permeability, net pay, water saturation, mobil-oil saturation, and other reservoir properties.

An integrated study of the Grayburg/San Andres reservoir, Foster and south Cowden fields, Ector County, Texas. Quarterly report, January 1--March 31, 1996

Energy Technology Data Exchange (ETDEWEB)

Trentham, R.C.; Weinbrandt, R.; Reeves, J.J.

1996-06-17

The principal objective of this research is to demonstrate in the field that 3D seismic data can be used to aid in identifying porosity zones, permeability barriers and thief zones and thereby improve waterflood design. Geologic and engineering data will be integrated with the geophysical data to result in a detailed reservoir characterization. Reservoir simulation will then be used to determine infill drilling potential and the optimum waterflood design for the project area. This design will be implemented and the success of the waterflood evaluated.

Mathematical and field analysis of longitudinal reservoir infill

Science.gov (United States)

Ke, W. T.; Capart, H.

2016-12-01

In reservoirs, severe problems are caused by infilled sediment deposits. In long term, the sediment accumulation reduces the capacity of reservoir storage and flood control benefits. In the short term, the sediment deposits influence the intakes of water-supply and hydroelectricity generation. For the management of reservoir, it is important to understand the deposition process and then to predict the sedimentation in reservoir. To investigate the behaviors of sediment deposits, we propose a one-dimensional simplified theory derived by the Exner equation to predict the longitudinal sedimentation distribution in idealized reservoirs. The theory models the reservoir infill geomorphic actions for three scenarios: delta progradation, near-dam bottom deposition, and final infill. These yield three kinds of self-similar analytical solutions for the reservoir bed profiles, under different boundary conditions. Three analytical solutions are composed by error function, complementary error function, and imaginary error function, respectively. The theory is also computed by finite volume method to test the analytical solutions. The theoretical and numerical predictions are in good agreement with one-dimensional small-scale laboratory experiment. As the theory is simple to apply with analytical solutions and numerical computation, we propose some applications to simulate the long-profile evolution of field reservoirs and focus on the infill sediment deposit volume resulting the uplift of near-dam bottom elevation. These field reservoirs introduced here are Wushe Reservoir, Tsengwen Reservoir, Mudan Reservoir in Taiwan, Lago Dos Bocas in Puerto Rico, and Sakuma Dam in Japan.

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

Reservoir Models for Gas Hydrate Numerical Simulation

Science.gov (United States)

Boswell, R.

2016-12-01

Scientific and industrial drilling programs have now providing detailed information on gas hydrate systems that will increasingly be the subject of field experiments. The need to carefully plan these programs requires reliable prediction of reservoir response to hydrate dissociation. Currently, a major emphasis in gas hydrate modeling is the integration of thermodynamic/hydrologic phenomena with geomechanical response for both reservoir and bounding strata. However, also critical to the ultimate success of these efforts is the appropriate development of input geologic models, including several emerging issues, including (1) reservoir heterogeneity, (2) understanding of the initial petrophysical characteristics of the system (reservoirs and seals), the dynamic evolution of those characteristics during active dissociation, and the interdependency of petrophysical parameters and (3) the nature of reservoir boundaries. Heterogeneity is ubiquitous aspect of every natural reservoir, and appropriate characterization is vital. However, heterogeneity is not random. Vertical variation can be evaluated with core and well log data; however, core data often are challenged by incomplete recovery. Well logs also provide interpretation challenges, particularly where reservoirs are thinly-bedded due to limitation in vertical resolution. This imprecision will extend to any petrophysical measurements that are derived from evaluation of log data. Extrapolation of log data laterally is also complex, and should be supported by geologic mapping. Key petrophysical parameters include porosity, permeability and it many aspects, and water saturation. Field data collected to date suggest that the degree of hydrate saturation is strongly controlled by/dependant upon reservoir quality and that the ratio of free to bound water in the remaining pore space is likely also controlled by reservoir quality. Further, those parameters will also evolve during dissociation, and not necessary in a simple

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

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

Considering heterogeneities by transmissibilities averaging on adapted meshes in reservoir simulation; Prise en compte des heterogeneites par prise de moyenne des transmissivites sur maillages adaptes en simulation de reservoir

Energy Technology Data Exchange (ETDEWEB)

Urgelli, D

1998-10-16

Reservoir heterogeneity can be described using geostatistical models. But these models generate the heterogeneity on millions of fine grid blocks, which leads to prohibitive computational costs for reservoir simulations. In order to reduce the number of grid blocks, averaging techniques are needed to up-scale the fine scale permeabilities to the larger scales appropriate for flow simulation and engineering calculations. Grid block permeability up-scaling for numerical reservoir simulations has been discussed for a long time in the literature. It is now recognized that a full permeability tensor is needed to get an accurate reservoir description. But, the equivalent permeability on coarse grid blocks cannot be used directly on the numerical scheme. Usually, the harmonic average of the coarse grid block permeability is used for the transmissibility calculation, but it might cause a loss of accuracy. The purpose of this thesis is to present a new procedure for computing the equivalent transmissibility in the discretized flow equations on Cartesian grids and Corner Point Geometry grids. An application of this technique to a finite volume type numerical scheme is detailed. The principle of this technique is to calculate a permeability term on a shifted block placed between the two adjacent blocks where the transmissibility must be determined. At the field scale, the flow region can be divided into two types : a linear flow pattern with a low pressure gradient far from the wells and a radial flow pattern with a high pressure gradient in the vicinity of the wells. The radial flow region is usually more important for the prediction of production forecast, because it is directly related to the well. This was demonstrated theoretically and numerically for 2-D problem. The transmissibility up-scaling in radial flow pattern consists to determine the transmissibilities in the vicinity of wells and the numerical Productivity Index simultaneously. This new method called `shifted

Rock music : a living legend of simulation modelling solves a reservoir problem by playing a different tune

Energy Technology Data Exchange (ETDEWEB)

Cope, G.

2008-07-15

Tight sand gas plays are low permeability reservoirs that have contributed an output of 5.7 trillion cubic feet of natural gas per year in the United States alone. Anadarko Petroleum Corporation has significant production from thousands of wells in Texas, Colorado, Wyoming and Utah. Hydraulic fracturing is the key to successful tight sand production. Production engineers use modelling software to calculate a well stimulation program in which large volumes of water are forced under high pressure in the reservoir, fracturing the rock and creating high permeability conduits for the natural gas to escape. Reservoir engineering researchers at the University of Calgary, led by world expert Tony Settari, have improved traditional software modelling of petroleum reservoirs by combining fracture analysis with geomechanical processes. This expertise has been a valuable asset to Anadarko, as the dynamic aspect can have a significant effect on the reservoir as it is being drilled. The challenges facing reservoir simulation is the high computing time needed for analyzing fluid production based on permeability, porosity, gas and fluid properties along with geomechanical analysis. Another challenge has been acquiring high quality field data. Using Anadarko's field data, the University of Calgary researchers found that water fracturing creates vertical primary fractures, and in some cases secondary fractures which enhance permeability. However, secondary fracturing is not permanent in all wells. The newly coupled geomechanical model makes it possible to model fracture growth more accurately. The Society of Petroleum Engineers recently awarded Settari with an award for distinguished achievement in improving the technique and practice of finding and producing petroleum. 1 fig.

Advances in coalbed methane reservoirs using integrated reservoir characterization and hydraulic fracturing in Karaganda coal basin, Kazakhstan

Science.gov (United States)

Ivakhnenko, Aleksandr; Aimukhan, Adina; Kenshimova, Aida; Mullagaliyev, Fandus; Akbarov, Erlan; Mullagaliyeva, Lylia; Kabirova, Svetlana; Almukhametov, Azamat

2017-04-01

Coalbed methane from Karaganda coal basin is considered to be an unconventional source of energy for the Central and Eastern parts of Kazakhstan. These regions are situated far away from the main traditional sources of oil and gas related to Precaspian petroleum basin. Coalbed methane fields in Karaganda coal basin are characterized by geological and structural complexity. Majority of production zones were characterized by high methane content and extremely low coal permeability. The coal reservoirs also contained a considerable natural system of primary, secondary, and tertiary fractures that were usually capable to accommodate passing fluid during hydraulic fracturing process. However, after closing was often observed coal formation damage including the loss of fluids, migration of fines and higher pressures required to treat formation than were expected. Unusual or less expected reservoir characteristics and values of properties of the coal reservoir might be the cause of the unusual occurred patterns in obtained fracturing, such as lithological peculiarities, rock mechanical properties and previous natural fracture systems in the coals. Based on these properties we found that during the drilling and fracturing of the coal-induced fractures have great sensitivity to complex reservoir lithology and stress profiles, as well as changes of those stresses. In order to have a successful program of hydraulic fracturing and avoid unnecessary fracturing anomalies we applied integrated reservoir characterization to monitor key parameters. In addition to logging data, core sample analysis was applied for coalbed methane reservoirs to observe dependence tiny lithological variations through the magnetic susceptibility values and their relation to permeability together with expected principal stress. The values of magnetic susceptibility were measured by the core logging sensor, which is equipped with the probe that provides volume magnetic susceptibility parameters

DEVELOPMENT OF RESERVOIR CHARACTERIZATION TECHNIQUES AND PRODUCTION MODELS FOR EXPLOITING NATURALLY FRACTURED RESERVOIRS

Energy Technology Data Exchange (ETDEWEB)

Michael L. Wiggins; Raymon L. Brown; Faruk Civan; Richard G. Hughes

2002-12-31

For many years, geoscientists and engineers have undertaken research to characterize naturally fractured reservoirs. Geoscientists have focused on understanding the process of fracturing and the subsequent measurement and description of fracture characteristics. Engineers have concentrated on the fluid flow behavior in the fracture-porous media system and the development of models to predict the hydrocarbon production from these complex systems. This research attempts to integrate these two complementary views to develop a quantitative reservoir characterization methodology and flow performance model for naturally fractured reservoirs. The research has focused on estimating naturally fractured reservoir properties from seismic data, predicting fracture characteristics from well logs, and developing a naturally fractured reservoir simulator. It is important to develop techniques that can be applied to estimate the important parameters in predicting the performance of naturally fractured reservoirs. This project proposes a method to relate seismic properties to the elastic compliance and permeability of the reservoir based upon a sugar cube model. In addition, methods are presented to use conventional well logs to estimate localized fracture information for reservoir characterization purposes. The ability to estimate fracture information from conventional well logs is very important in older wells where data are often limited. Finally, a desktop naturally fractured reservoir simulator has been developed for the purpose of predicting the performance of these complex reservoirs. The simulator incorporates vertical and horizontal wellbore models, methods to handle matrix to fracture fluid transfer, and fracture permeability tensors. This research project has developed methods to characterize and study the performance of naturally fractured reservoirs that integrate geoscience and engineering data. This is an important step in developing exploitation strategies for

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

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.

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.

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

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

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

Thermal-permeability structure and recharge conditions of the Mutnovsky high-temperature geothermal field (Kamchatka, Russia)

Science.gov (United States)

Kiryukhin, A. V.; Polyakov, A. Y.; Usacheva, O. O.; Kiryukhin, P. A.

2018-05-01

The Mutnovsky geothermal area is part of the Eastern Kamchatka active volcano belt. Mutnovsky, 80 kY old and an aging strato-volcano (a complex of 4 composite volcanic cones), acts as a magma- and water-injector into the 25-km-long North Mutnovsky extension zone. Magmatic injection events (dykes) are associated with plane-oriented MEQ (Micro Earth Quakes) clusters, most of them occurring in the NE sector of the volcano (2 × 10 km2) at elevations from -4 to -2 km, while some magmatic injections occur at elevations from -6.0 to -4.0 km below the Mutnovsky production field. Water recharge of production reservoirs is from the Mutnovsky volcano crater glacier (+1500 to +1800 masl), which was confirmed by water isotopic data (δD, δ18O) of production wells at an earlier stage of development. The Mutnovsky (Dachny) 260-310 °C high-temperature production geothermal reservoir with a volume of 16 km3 is at the junction of NNE- and NE-striking normal faults, which coincides with the current dominant dyke injection orientation. TOUGH2-modeling estimates of the reservoir properties are as follows: the reservoir permeability is 90-600 e-15 m2, the deep upflow recharge is 80 kg/s and the enthalpy is 1420 kJ/kg. Modeling was used to reproduce the history of the Mutnovsky (Dachny) reservoir exploitation since 1983 with an effective power of 48 MWe by 2016. Modeling also showed that the reservoir is capable of yielding 65-83 MWe of sustainable production until 2055, if additional production drilling in the SE part of the field is performed. Moreover, this power value may increase to 87-105 MWe if binary technologies are applied. Modeling also shows that the predicted power is sensitive to local meteoric water influx during development. Conceptual iTOUGH2-EOS1sc thermal hydrodynamic modeling of the Mutnovsky magma-hydrothermal system as a whole reasonably explains its evolution over the last 1500-5000 years in terms of heat recharge (dyke injection from the Mutnovsky-4 funnel) and

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.

Effect of wettability on scale-up of multiphase flow from core-scale to reservoir fine-grid-scale

Energy Technology Data Exchange (ETDEWEB)

Chang, Y.C.; Mani, V.; Mohanty, K.K. [Univ. of Houston, TX (United States)

1997-08-01

Typical field simulation grid-blocks are internally heterogeneous. The objective of this work is to study how the wettability of the rock affects its scale-up of multiphase flow properties from core-scale to fine-grid reservoir simulation scale ({approximately} 10{prime} x 10{prime} x 5{prime}). Reservoir models need another level of upscaling to coarse-grid simulation scale, which is not addressed here. Heterogeneity is modeled here as a correlated random field parameterized in terms of its variance and two-point variogram. Variogram models of both finite (spherical) and infinite (fractal) correlation length are included as special cases. Local core-scale porosity, permeability, capillary pressure function, relative permeability functions, and initial water saturation are assumed to be correlated. Water injection is simulated and effective flow properties and flow equations are calculated. For strongly water-wet media, capillarity has a stabilizing/homogenizing effect on multiphase flow. For small variance in permeability, and for small correlation length, effective relative permeability can be described by capillary equilibrium models. At higher variance and moderate correlation length, the average flow can be described by a dynamic relative permeability. As the oil wettability increases, the capillary stabilizing effect decreases and the deviation from this average flow increases. For fractal fields with large variance in permeability, effective relative permeability is not adequate in describing the flow.

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.

Analysis and application of classification methods of complex carbonate reservoirs

Science.gov (United States)

Li, Xiongyan; Qin, Ruibao; Ping, Haitao; Wei, Dan; Liu, Xiaomei

2018-06-01

There are abundant carbonate reservoirs from the Cenozoic to Mesozoic era in the Middle East. Due to variation in sedimentary environment and diagenetic process of carbonate reservoirs, several porosity types coexist in carbonate reservoirs. As a result, because of the complex lithologies and pore types as well as the impact of microfractures, the pore structure is very complicated. Therefore, it is difficult to accurately calculate the reservoir parameters. In order to accurately evaluate carbonate reservoirs, based on the pore structure evaluation of carbonate reservoirs, the classification methods of carbonate reservoirs are analyzed based on capillary pressure curves and flow units. Based on the capillary pressure curves, although the carbonate reservoirs can be classified, the relationship between porosity and permeability after classification is not ideal. On the basis of the flow units, the high-precision functional relationship between porosity and permeability after classification can be established. Therefore, the carbonate reservoirs can be quantitatively evaluated based on the classification of flow units. In the dolomite reservoirs, the average absolute error of calculated permeability decreases from 15.13 to 7.44 mD. Similarly, the average absolute error of calculated permeability of limestone reservoirs is reduced from 20.33 to 7.37 mD. Only by accurately characterizing pore structures and classifying reservoir types, reservoir parameters could be calculated accurately. Therefore, characterizing pore structures and classifying reservoir types are very important to accurate evaluation of complex carbonate reservoirs in the Middle East.

Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface groundwater: Background, base cases, shallow reservoirs, short-term gas, and water transport

Science.gov (United States)

Reagan, Matthew T; Moridis, George J; Keen, Noel D; Johnson, Jeffrey N

2015-01-01

Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes. Key Points: Short-term leakage fractured reservoirs requires high-permeability pathways Production strategy affects the likelihood and magnitude of gas release Gas release is likely short-term, without additional driving forces PMID

Production-log base model for carbonate permeability distribution and steam flood optimization

Energy Technology Data Exchange (ETDEWEB)

Ahamed, S.F.; Choudhry, M.A.; Abdulbaqi, J.B. [Kuwait Gulf Oil Co. (Kuwait)

2008-10-15

This paper presented a model for the effective management of primary and thermal oil recovery operations in the Wafra Field in Kuwait, where a small huff and puff project was carried out in 1998 to determine if steam injection was a feasible recovery option for the field. The Eocene heavy oil reservoirs of the Wafra Field are carbonate rock admixtures with gypsum and anhydrite. They are the shallowest of the field's productive horizons and exhibit a high degree of fluid flow heterogeneity. The assessment of vertical and lateral permeability variation is a key factor for success of the reservoir development plan. Steam injection began in 2006 in a small scale test (SST) to determine if the innovative technology could produce steam from effluent water and to test the viability of steam injection in carbonate reservoirs. Following the success of the SST, a large scale pilot (LSP) is schedule to start in 2009. It can be used for completion strategies of injectors and producers in steam injection. The model showed that the productivity of the Eocene wells could be correlated with common available logs to develop a log based-permeability model. A series of cross plots for the perforated intervals of high and low productivity wells were constructed to develop a relationship between well productivity and location of log parameters on the plots. A relationship between rock quality, productivity and conventional log parameters was established. It was concluded that the vertical permeability and interwell continuity in the Eocene wells can be used to optimize new well placement for horizontal and vertical infill drilling. The model is also an effective tool to predict the steam injectivity profile to understand the anomalies related to temperature-depth distribution. The model can be used to improve the efficiency of formation heating by optimizing the steam flood process and steam pattern well completion. 16 refs.

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.

Compressible fluid flow through rocks of variable permeability

International Nuclear Information System (INIS)

Lin, W.

1977-01-01

The effectiveness of course-grained igneous rocks as shelters for burying radioactive waste can be assessed by determining the rock permeabilities at their in situ pressures and stresses. Analytical and numerical methods were used to solve differential equations of one-dimensional fluid flow through rocks with permeabilities from 10 4 to 1 nD. In these calculations, upstream and downstream reservoir volumes of 5, 50, and 500 cm 3 were used. The optimal size combinations of the two reservoirs were determined for measurements of permeability, stress, strain, acoustic velocity, and electrical conductivity on low-porosity, coarse-grained igneous rocks

Numerical Well Testing Interpretation Model and Applications in Crossflow Double-Layer Reservoirs by Polymer Flooding

Directory of Open Access Journals (Sweden)

Haiyang Yu

2014-01-01

Full Text Available This work presents numerical well testing interpretation model and analysis techniques to evaluate formation by using pressure transient data acquired with logging tools in crossflow double-layer reservoirs by polymer flooding. A well testing model is established based on rheology experiments and by considering shear, diffusion, convection, inaccessible pore volume (IPV, permeability reduction, wellbore storage effect, and skin factors. The type curves were then developed based on this model, and parameter sensitivity is analyzed. Our research shows that the type curves have five segments with different flow status: (I wellbore storage section, (II intermediate flow section (transient section, (III mid-radial flow section, (IV crossflow section (from low permeability layer to high permeability layer, and (V systematic radial flow section. The polymer flooding field tests prove that our model can accurately determine formation parameters in crossflow double-layer reservoirs by polymer flooding. Moreover, formation damage caused by polymer flooding can also be evaluated by comparison of the interpreted permeability with initial layered permeability before polymer flooding. Comparison of the analysis of numerical solution based on flow mechanism with observed polymer flooding field test data highlights the potential for the application of this interpretation method in formation evaluation and enhanced oil recovery (EOR.

Effects of mechanical layering on hydrofracture emplacement and fluid transport in reservoirs

Directory of Open Access Journals (Sweden)

Sonja Leonie Philipp

2013-12-01

Full Text Available Fractures generated by internal fluid pressure, for example, dykes, mineral veins, many joints and man-made hydraulic fractures, are referred to as hydrofractures. Together with shear fractures, they contribute significantly to the permeability of fluid reservoirs such as those of petroleum, geothermal water, and groundwater. Analytical and numerical models show that – in homogeneous host rocks – any significant overpressure in hydrofractures theoretically generates very high crack tip tensile stresses. Consequently, overpressured hydrofractures should propagate and help to form interconnected fracture systems that would then contribute to the permeability of fluid reservoirs. Field observations, however, show that in heterogeneous and anisotropic, e.g., layered, rocks many hydrofractures become arrested or offset at layer contacts and do not form vertically interconnected networks. The most important factors that contribute to hydrofracture arrest are discontinuities (including contacts, stiffness changes between layers, and stress barriers, where the local stress field is unfavourable to hydrofracture propagation. A necessary condition for a hydrofracture to propagate to the surface is that the stress field along its potential path is everywhere favourable to extension-fracture formation so that the probability of hydrofracture arrest is minimised. Mechanical layering and the resulting heterogeneous stress field largely control whether evolving hydrofractures become confined to single layers (strata¬bound frac¬tures or not (non-stratabound fractures and, there¬fore, if a vertically intercon¬nec¬ted fracture system forms. Non-stratabound hydrofractures may propagate through many layers and generate interconnected fracture systems. Such systems commonly reach the percolation threshold and largely control the overall permeability of the fluid reservoirs within which they develop.

Geological and Petrophysical Characterization of the Ferron Sandstone for 3-D Simulation of a Fluvial-Deltaic Reservoir

Energy Technology Data Exchange (ETDEWEB)

Chidsey, Jr, Thomas C.

2001-10-31

The objective of the Ferron Sandstone project was to develop a comprehensive, interdisciplinary, quantitative characterization f fluvial-deltaic reservoir to allow realistic interwell and reservoir-scale models to be developed for improved oil-field development in similar reservoirs world-wide. Quantitative geological and petrophysical information on the Cretaceous Ferron Sandstone in east-central Utah was collected. Both new and existing data was integrated into a three-dimensional model of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Simulation results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations.

Fracture properties from tight reservoir outcrop analogues with application to geothermal exploration

Science.gov (United States)

Philipp, Sonja L.; Reyer, Dorothea; Afsar, Filiz; Bauer, Johanna F.; Meier, Silke; Reinecker, John

2015-04-01

In geothermal reservoirs, similar to other tight reservoirs, fluid flow may be intensely affected by fracture systems, in particular those associated with fault zones. When active (slipping) the fault core, that is, the inner part of a fault zone, which commonly consists of breccia or gouge, can suddenly develop high permeability. Fault cores of inactive fault zones, however, may have low permeabilities and even act as flow barriers. In the outer part of a fault zone, the damage zone, permeability depends mainly on the fracture properties, that is, the geometry (orientation, aperture, density, connectivity, etc.) of the fault-associated fracture system. Mineral vein networks in damage zones of deeply eroded fault zones in palaeogeothermal fields demonstrate their permeability. In geothermal exploration, particularly for hydrothermal reservoirs, the orientation of fault zones in relation to the current stress field as well as their internal structure, in particular the properties of the associated fracture system, must be known as accurately as possible for wellpath planning and reservoir engineering. Here we present results of detailed field studies and numerical models of fault zones and associated fracture systems in palaeogeo¬thermal fields and host rocks for geothermal reservoirs from various stratigraphies, lithologies and tectonic settings: (1) 74 fault zones in three coastal sections of Upper Triassic and Lower Jurassic age (mudstones and limestone-marl alternations) in the Bristol Channel Basin, UK. (2) 58 fault zones in 22 outcrops from Upper Carboniferous to Upper Cretaceous in the Northwest German Basin (siliciclastic, carbonate and volcanic rocks); and (3) 16 fault zones in 9 outcrops in Lower Permian to Middle Triassic (mainly sandstone and limestone) in the Upper Rhine Graben shoulders. Whereas (1) represent palaeogeothermal fields with mineral veins, (2) and (3) are outcrop analogues of reservoir horizons from geothermal exploration. In the study

Orthogonal Test Analysis on Conditions Affecting Electricity Generation Performance of an Enhanced Geothermal System at Yangbajing Geothermal Field

Directory of Open Access Journals (Sweden)

Yuchao Zeng

2017-12-01

Full Text Available The main conditions affecting electricity generation performance of an enhanced geothermal system (EGS include reservoir porosity, reservoir permeability, rock heat conductivity, water production rate and injection temperature. Presently there is lack of systematic research the relative importance of the five aforementioned conditions. The orthogonal test method is a statistical approach to analyze multi-factor and multi-level influence on system performance. In this work, based on the geological data at Yangbajing geothermal field, we analyzed the five conditions affecting the electricity generation performance of EGS, and ranked the relative importance of the five factors. The results show that the order of the relative importance of the conditions on electric power is water production rate > injection temperature > reservoir porosity > rock heat conductivity > reservoir permeability; the order of the relative importance of the conditions on reservoir impedance is reservoir permeability > injection temperature > water production rate > reservoir porosity > rock heat conductivity; the order of the relative importance of the conditions on pump power is water production rate > reservoir permeability > injection temperature > reservoir porosity > rock heat conductivity, and; the order of the relative importance of the conditions on energy efficiency is water production rate > reservoir permeability > reservoir porosity > injection temperature > rock heat conductivity. The construction of an EGS reservoir should be located at a formation with higher reservoir porosity or rock heat conductivity, while the determination of reservoir permeability, water production rate and injection temperature should be based on the comprehensive target.

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.

Using artificial intelligence to predict permeability from petrographic data

Energy Technology Data Exchange (ETDEWEB)

Maqsood Ali; Adwait Chawathe [New Mexico Petroleum Recovery Research Centre (Mexico)

2000-10-01

Petrographic data collected during thin section analysis can be invaluable for understanding the factors that control permeability distribution. Reliable prediction of permeability is important for reservoir characterization. The petrographic elements (mineralogy, porosity types, cements and clays, and pore morphology) interact with each other uniquely to generate a specific permeability distribution. It is difficult to quantify accurately this interaction and its consequent effect on permeability, emphasizing the non-linear nature of the process. To capture these non-linear interactions, neural networks were used to predict permeability from petrographic data. The neural net was used as a multivariate correlative tool because of its ability to learn the non-linear relationships between multiple input and output variables. The study was conducted on the upper Queen formation called the Shattuck Member (Permian age). The Shattuck Member is composed of very fine-grained arkosic sandstone. The core samples were available from the Sulimar Queen and South Lucky Lake fields located in Chaves County, New Mexico. Nineteen petrographic elements were collected for each permeability value using a combined minipermeameter-petrographic technique. In order to reduce noise and overfitting the permeability model, these petrographic elements were screened, and their control (ranking) with respect to permeability was determined using fuzzy logic. Since the fuzzy logic algorithm provides unbiased ranking, it was used to reduce the dimensionality of the input variables. Based on the fuzzy logic ranking, only the most influential petrographic elements were selected as inputs for permeability prediction. The neural net was trained and tested using data from Well 1-16 in the Sulimar Queen field. Relying on the ranking obtained from the fuzzy logic analysis, the net was trained using the most influential three, five, and ten petrographic elements. A fast algorithm (the scaled conjugate

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

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.

A Mathematical Pressure Transient Analysis Model for Multiple Fractured Horizontal Wells in Shale Gas Reservoirs

Directory of Open Access Journals (Sweden)

Yan Zeng

2018-01-01

Full Text Available Multistage fractured horizontal wells (MFHWs have become the main technology for shale gas exploration. However, the existing models have neglected the percolation mechanism in nanopores of organic matter and failed to consider the differences among the reservoir properties in different areas. On that account, in this study, a modified apparent permeability model was proposed describing gas flow in shale gas reservoirs by integrating bulk gas flow in nanopores and gas desorption from nanopores. The apparent permeability was introduced into the macroseepage model to establish a dynamic pressure analysis model for MFHWs dual-porosity formations. The Laplace transformation and the regular perturbation method were used to obtain an analytical solution. The influences of fracture half-length, fracture permeability, Langmuir volume, matrix radius, matrix permeability, and induced fracture permeability on pressure and production were discussed. Results show that fracture half-length, fracture permeability, and induced fracture permeability exert a significant influence on production. A larger Langmuir volume results in a smaller pressure and pressure derivative. An increase in matrix permeability increases the production rate. Besides, this model fits the actual field data relatively well. It has a reliable theoretical foundation and can preferably describe the dynamic changes of pressure in the exploration process.

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

Field data provide estimates of effective permeability, fracture spacing, well drainage area and incremental production in gas shales

KAUST Repository

Eftekhari, Behzad; Marder, M.; Patzek, Tadeusz

2018-01-01

the external unstimulated reservoir. This allows us to estimate for the first time the effective permeability of the unstimulated shale and the spacing of fractures in the stimulated region. From an analysis of wells in the Barnett shale, we find

Fracture network topology and characterization of structural permeability

Science.gov (United States)

Hansberry, Rowan; King, Rosalind; Holford, Simon

2017-04-01

There are two fundamental requirements for successful geothermal development: elevated temperatures at accessible depths, and a reservoir from which fluids can be extracted. The Australian geothermal sector has successfully targeted shallow heat, however, due in part to the inherent complexity of targeting permeability, obtaining adequate flow rates for commercial production has been problematic. Deep sedimentary aquifers are unlikely to be viable geothermal resources due to the effects of diagenetic mineral growth on rock permeability. Therefore, it is likely structural permeability targets, exploiting natural or induced fracture networks will provide the primary means for fluid flow in geothermal, as well as unconventional gas, reservoirs. Recent research has focused on the pattern and generation of crustal stresses across Australia, while less is known about the resultant networks of faults, joints, and veins that can constitute interconnected sub-surface permeability pathways. The ability of a fracture to transmit fluid is controlled by the orientation and magnitude of the in-situ stress field that acts on the fracture walls, rock strength, and pore pressure, as well as fracture properties such as aperture, orientation, and roughness. Understanding the distribution, orientation and character of fractures is key to predicting structural permeability. This project focuses on extensive mapping of fractures over various scales in four key Australian basins (Cooper, Otway, Surat and Perth) with the potential to host geothermal resources. Seismic attribute analysis is used in concert with image logs from petroleum wells, and field mapping to identify fracture networks that are usually not resolved in traditional seismic interpretation. We use fracture network topology to provide scale-invariant characterisation of fracture networks from multiple data sources to assess similarity between data sources, and fracture network connectivity. These results are compared with

Application of integrated reservoir management and reservoir characterization to optimize infill drilling, Class II

Energy Technology Data Exchange (ETDEWEB)

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

2000-03-16

The major purpose of this project was to demonstrate the use of cost effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability carbonate reservoirs such as the North Robertson (Clearfork) Unit.

Effective Stress Law in Unconventional Reservoirs under Different Boundary Conditions

Science.gov (United States)

Saurabh, S.; Harpalani, S.

2017-12-01

Unconventional reservoirs have attracted a great deal of research interest worldwide during the past two decades. Low permeability and specialized techniques required to exploit these resources present opportunities for improvement in both production rates and ultimate recovery. Understanding subsurface stress modifications and permeability evolution are valuable when evaluating the prospects of unconventional reservoirs. These reservoir properties are functions of effective stress. As a part of this study, effective stress law, specifically the variation of anisotropic Biot's coefficient under various boundary conditions believed to exist in gas reservoirs by different researchers, has been established. Pressure-dependent-permeability (PdK) experiments were carried out on San Juan coal under different boundary conditions, that is, uniaxial strain condition and constant volume condition. Stress and strain in the vertical and horizontal directions were monitored throughout the experiment. Data collected during the experiments was used to determine the Biot's coefficient in vertical and horizontal directions under these two boundary conditions, treating coal as transversely isotropic. The variation of Biot's coefficient was found to be well correlated with the variation in coal permeability. Based on the estimated values of Biot's coefficients, a theory of variation in its value is presented for other boundary conditions. The findings of the study shed light on the inherent behavior of Biot's coefficient under different reservoir boundary conditions. This knowledge can improve the modeling work requiring estimation of effective stress in reservoirs, such as, pressure-/stress- dependent permeability. At the same time, if the effective stresses are known with more certainty by other methods, it enables assessment of the unknown reservoir boundary conditions.

Frictional stability-permeability relationships for fractures in shales

Science.gov (United States)

Fang, Yi; Elsworth, Derek; Wang, Chaoyi; Ishibashi, Takuya; Fitts, Jeffrey P.

2017-03-01

There is wide concern that fluid injection in the subsurface, such as for the stimulation of shale reservoirs or for geological CO2 sequestration (GCS), has the potential to induce seismicity that may change reservoir permeability due to fault slip. However, the impact of induced seismicity on fracture permeability evolution remains unclear due to the spectrum of modes of fault reactivation (e.g., stable versus unstable). As seismicity is controlled by the frictional response of fractures, we explore friction-stability-permeability relationships through the concurrent measurement of frictional and hydraulic properties of artificial fractures in Green River shale (GRS) and Opalinus shale (OPS). We observe that carbonate-rich GRS shows higher frictional strength but weak neutral frictional stability. The GRS fracture permeability declines during shearing while an increased sliding velocity reduces the rate of permeability decline. By comparison, the phyllosilicate-rich OPS has lower friction and strong stability while the fracture permeability is reduced due to the swelling behavior that dominates over the shearing induced permeability reduction. Hence, we conclude that the friction-stability-permeability relationship of a fracture is largely controlled by mineral composition and that shale mineral compositions with strong frictional stability may be particularly subject to permanent permeability reduction during fluid infiltration.

MAPPING OF RESERVOIR PROPERTIES AND FACIES THROUGH INTEGRATION OF STATIC AND DYNAMIC DATA

Energy Technology Data Exchange (ETDEWEB)

Albert C. Reynolds; Dean S. Oliver; Fengjun Zhang; Yannong Dong; Jan Arild Skjervheim; Ning Liu

2003-01-01

models. In general, boundary locations, average permeability and porosity, relative permeability curves, and local flow properties may all need to be adjusted to achieve a plausible reservoir model that honors all data. In this project, we will characterize the distribution of geologic facies as an indicator random field, making use of the tools of geostatistics as well as the tools of inverse and probability theory for data integration.

Reservoir Simulation on the Cerro Prieto Geothermal Field: A Continuing Study

Energy Technology Data Exchange (ETDEWEB)

Castaneda, M.; Marquez, R.; Arellano, V.; Esquer, C.A.

1983-12-15

The Cerro Prieto geothermal field is a liquid-dominated geothermal reservoir of complex geological and hydrological structure. It is located at the southern end of the Salton-Mexicali trough which includes other geothermal anomalies as Heber and East Mesa. Although in 1973, the initial power plant installed capacity was 75 MW of electrical power, this amount increased to 180 MW in 1981 as field development continued. It is expected to have a generating capacity of 620 MW by the end of 1985, when two new plants will be completely in operation. Questions about field deliverability, reservoir life and ultimate recovery related to planned installations are being presently asked. Numerical modeling studies can give very valuable answers to these questions, even at the early stages in the development of a field. An effort to simulate the Cerro Prieto geothermal reservoir has been undergoing for almost two years. A joint project among Comision Federal de Electricidad (CFE), Instituto de Investigaciones Electricas (IIE) and Intercomp of Houstin, Texas, was created to perform reservoir engineering and simulation studies on this field. The final project objective is tosimulate the behavior of the old field region when production from additional wells located in the undeveloped field zones will be used for feeding the new power plants.

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.

The Bakken - An Unconventional Petroleum and Reservoir System

Energy Technology Data Exchange (ETDEWEB)

Sarg, J.

2011-12-31

An integrated geologic and geophysical study of the Bakken Petroleum System, in the Williston basin of North Dakota and Montana indicates that: (1) dolomite is needed for good reservoir performance in the Middle Bakken; (2) regional and local fractures play a significant role in enhancing permeability and well production, and it is important to recognize both because local fractures will dominate in on-structure locations; and (3) the organic-rich Bakken shale serves as both a source and reservoir rock. The Middle Bakken Member of the Bakken Formation is the target for horizontal drilling. The mineralogy across all the Middle Bakken lithofacies is very similar and is dominated by dolomite, calcite, and quartz. This Member is comprised of six lithofacies: (A) muddy lime wackestone, (B) bioturbated, argillaceous, calcareous, very fine-grained siltstone/sandstone, (C) planar to symmetrically ripple to undulose laminated, shaly, very fine-grained siltstone/sandstone, (D) contorted to massive fine-grained sandstone, to low angle, planar cross-laminated sandstone with thin discontinuous shale laminations, (E) finely inter-laminated, bioturbated, dolomitic mudstone and dolomitic siltstone/sandstone to calcitic, whole fossil, dolomitic lime wackestone, and (F) bioturbated, shaly, dolomitic siltstone. Lithofacies B, C, D, and E can all be reservoirs, if quartz and dolomite-rich (facies D) or dolomitized (facies B, C, E). Porosity averages 4-8%, permeability averages 0.001-0.01 mD or less. Dolomitic facies porosity is intercrystalline and tends to be greater than 6%. Permeability may reach values of 0.15 mD or greater. This appears to be a determinant of high productive wells in Elm Coulee, Parshall, and Sanish fields. Lithofacies G is organic-rich, pyritic brown/black mudstone and comprises the Bakken shales. These shales are siliceous, which increases brittleness and enhances fracture potential. Mechanical properties of the Bakken reveal that the shales have similar

Experimental Study on the Effects of Stress Variations on the Permeability of Feldspar-Quartz Sandstone

Directory of Open Access Journals (Sweden)

Fugang Wang

2017-01-01

Full Text Available The multistage and discontinuous nature of the injection process used in the geological storage of CO2 causes reservoirs to experience repeated loading and unloading. The reservoir permeability changes caused by this phenomenon directly impact the CO2 injection process and the process of CO2 migration in the reservoirs. Through laboratory experiments, variations in the permeability of sandstone in the Liujiagou formation of the Ordos CO2 capture and storage (CCS demonstration project were analyzed using cyclic variations in injection pressure and confining pressure and multistage loading and unloading. The variation in the micropore structure and its influence on the permeability were analyzed based on micropore structure tests. In addition, the effects of multiple stress changes on the permeability of the same type of rock with different clay minerals content were also analyzed. More attention should be devoted to the influence of pressure variations on permeability in evaluations of storage potential and studies of CO2 migration in reservoirs in CCS engineering.

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.

Numerical solution of fractured horizontal wells in shale gas reservoirs considering multiple transport mechanisms

Science.gov (United States)

Zhao, Yu-long; Tang, Xu-chuan; Zhang, Lie-hui; Tang, Hong-ming; Tao, Zheng-Wu

2018-06-01

The multiscale pore size and specific gas storage mechanism in organic-rich shale gas reservoirs make gas transport in such reservoirs complicated. Therefore, a model that fully incorporates all transport mechanisms and employs an accurate numerical method is urgently needed to simulate the gas production process. In this paper, a unified model of apparent permeability was first developed, which took into account multiple influential factors including slip flow, Knudsen diffusion (KD), surface diffusion, effects of the adsorbed layer, permeability stress sensitivity, and ad-/desorption phenomena. Subsequently, a comprehensive mathematical model, which included the model of apparent permeability, was derived to describe gas production behaviors. Thereafter, on the basis of unstructured perpendicular bisection grids and finite volume method, a fully implicit numerical simulator was developed using Matlab software. The validation and application of the new model were confirmed using a field case reported in the literature. Finally, the impacts of related influencing factors on gas production were analyzed. The results showed that KD resulted in a negligible impact on gas production in the proposed model. The smaller the pore size was, the more obvious the effects of the adsorbed layer on the well production rate would be. Permeability stress sensitivity had a slight effect on well cumulative production in shale gas reservoirs. Adsorbed gas made a major contribution to the later flow period of the well; the greater the adsorbed gas content, the greater the well production rate would be. This paper can improve the understanding of gas production in shale gas reservoirs for petroleum engineers.

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%.

Processing of reservoir data for diagenesis simulation; Traitement des donnees de reservoir en vue d`une simulation de la diagenese

Energy Technology Data Exchange (ETDEWEB)

Pelletier, I.

1997-12-18

Diagenetic minerals frequently damage reservoir permeability. A numerical model which couples chemical reactions and transport of dissolved elements can help to predict both location and magnitude of cementations. The present Ph.D. examines how can be applied such a modelling approach to a complex heterogeneous reservoir. Petrographical data from core samples are used as input data, or alternatively as controls for validating the modelling results. The measurements, acquired with dm-to-m spacing are too numerous to be integrated in a reactions-transport code. The usual up-scaling methods, called Homogenization, conserve only the fluid flow properties. A new method, called `Gathering` takes into account material transport balance. It is proposed in the first part of the dissertation. In the second part, an application of Gathering is done simulating illitization in the sub-arkosic sandstones of the Ness formation (Brent Group) in a North Sea field, Dunbar.. As a prerequisite, data accuracy is examined for a set of `routine measurements` (100 points counting on thin section, XR-diffractometry and gas porosity/permeability). (author) 60 refs.

3D Reservoir Modeling of Semutang Gas Field: A lonely Gas field in Chittagong-Tripura Fold Belt, with Integrated Well Log, 2D Seismic Reflectivity and Attributes.

Science.gov (United States)

Salehin, Z.; Woobaidullah, A. S. M.; Snigdha, S. S.

2015-12-01

Bengal Basin with its prolific gas rich province provides needed energy to Bangladesh. Present energy situation demands more Hydrocarbon explorations. Only 'Semutang' is discovered in the high amplitude structures, where rest of are in the gentle to moderate structures of western part of Chittagong-Tripura Fold Belt. But it has some major thrust faults which have strongly breached the reservoir zone. The major objectives of this research are interpretation of gas horizons and faults, then to perform velocity model, structural and property modeling to obtain reservoir properties. It is needed to properly identify the faults and reservoir heterogeneities. 3D modeling is widely used to reveal the subsurface structure in faulted zone where planning and development drilling is major challenge. Thirteen 2D seismic and six well logs have been used to identify six gas bearing horizons and a network of faults and to map the structure at reservoir level. Variance attributes were used to identify faults. Velocity model is performed for domain conversion. Synthetics were prepared from two wells where sonic and density logs are available. Well to seismic tie at reservoir zone shows good match with Direct Hydrocarbon Indicator on seismic section. Vsh, porosity, water saturation and permeability have been calculated and various cross plots among porosity logs have been shown. Structural modeling is used to make zone and layering accordance with minimum sand thickness. Fault model shows the possible fault network, those liable for several dry wells. Facies model have been constrained with Sequential Indicator Simulation method to show the facies distribution along the depth surfaces. Petrophysical models have been prepared with Sequential Gaussian Simulation to estimate petrophysical parameters away from the existing wells to other parts of the field and to observe heterogeneities in reservoir. Average porosity map for each gas zone were constructed. The outcomes of the research

Integrated Analysis Seismic Inversion and Rockphysics for Determining Secondary Porosity Distribution of Carbonate Reservoir at “FR” Field

Science.gov (United States)

Rosid, M. S.; Augusta, F. F.; Haidar, M. W.

2018-05-01

In general, carbonate secondary pore structure is very complex due to the significant diagenesis process. Therefore, the determination of carbonate secondary pore types is an important factor which is related to study of production. This paper mainly deals not only to figure out the secondary pores types, but also to predict the distribution of the secondary pore types of carbonate reservoir. We apply Differential Effective Medium (DEM) for analyzing pore types of carbonate rocks. The input parameter of DEM inclusion model is fraction of porosity and the output parameters are bulk moduli and shear moduli as a function of porosity, which is used as input parameter for creating Vp and Vs modelling. We also apply seismic post-stack inversion technique that is used to map the pore type distribution from 3D seismic data. Afterward, we create porosity cube which is better to use geostatistical method due to the complexity of carbonate reservoir. Thus, the results of this study might show the secondary porosity distribution of carbonate reservoir at “FR” field. In this case, North – Northwest of study area are dominated by interparticle pores and crack pores. Hence, that area has highest permeability that hydrocarbon can be more accumulated.

The Effect of External Magnetic Field on Dielectric Permeability of Multiphase Ferrofluids

Science.gov (United States)

Dotsenko, O. A.; Pavlova, A. A.; Dotsenko, V. S.

2018-03-01

Nowadays, ferrofluids are applied in various fields of science and technology, namely space, medicine, geology, biology, automobile production, etc. In order to investigate the feasibility of applying ferrofluids in magnetic field sensors, the paper presents research into the influence of the external magnetic field on dielectric permeability of ferrofluids comprising magnetite nanopowder, multiwall carbon nanotubes, propanetriol and deionized water. The real and imaginary parts of the dielectric permeability change respectively by 3.7 and 0.5% when applying the magnetic field parallel to the electric. The findings suggest that the considered ferrofluid can be used as a magnetic level gauge or in design of variable capacitors.

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.

Field guide to Muddy Formation outcrops, Crook County, Wyoming

Energy Technology Data Exchange (ETDEWEB)

Rawn-Schatzinger, V.

1993-11-01

The objectives of this research program are to (1) determine the reservoir characteristics and production problems of shoreline barrier reservoirs; and (2) develop methods and methodologies to effectively characterize shoreline bamer reservoirs to predict flow patterns of injected and produced fluids. Two reservoirs were selected for detailed reservoir characterization studies -- Bell Creek field, Carter County, Montana that produces from the Lower Cretaceous (Albian-Cenomanian) Muddy Formation, and Patrick Draw field, Sweetwater County, Wyoming that produces from the Upper Cretaceous (Campanian) Almond Formation of the Mesaverde Group. An important component of the research project was to use information from outcrop exposures of the producing formations to study the spatial variations of reservoir properties and the degree to which outcrop information can be used in the construction of reservoir models. This report contains the data and analyses collected from outcrop exposures of the Muddy Formation, located in Crook County, Wyoming, 40 miles south of Bell Creek oil field. The outcrop data set contains permeability, porosity, petrographic, grain size and geologic data from 1-inch-diameter core plugs chilled from the outcrop face, as well as geological descriptions and sedimentological interpretations of the outcrop exposures. The outcrop data set provides information about facies characteristics and geometries and the spatial distribution of permeability and porosity on interwell scales. Appendices within this report include a micropaleontological analyses of selected outcrop samples, an annotated bibliography of papers on the Muddy Formation in the Powder River Basin, and over 950 permeability and porosity values measured from 1-inch-diameter core plugs drilled from the outcrop. All data contained in this resort are available in electronic format upon request. The core plugs drilled from the outcrop are available for measurement.

Effect of pore structure on the seepage characteristics of tight sandstone reservoirs: A case study of Upper Jurassic Penglaizhen Fm reservoirs in the western Sichuan Basin

Directory of Open Access Journals (Sweden)

Liqiang Sima

2017-01-01

Full Text Available Tight sandstone reservoirs are characterized by complex pore structures and strong heterogeneity, and their seepage characteristics are much different from those of conventional sandstone reservoirs. In this paper, the tight sandstone reservoirs of Upper Jurassic Penglaizhen Fm in western Sichuan Basin were analyzed in terms of their pore structures by using the data about physical property, mercury injection and nuclear magnetic resonance (NMR tests. Then, the seepage characteristics and the gas–water two-phase migration mechanisms and distribution of tight sandstone reservoirs with different types of pore structures in the process of hydrocarbon accumulation and development were simulated by combining the relative permeability experiment with the visual microscopic displacement model. It is shown that crotch-like viscous fingering occurs in the process of gas front advancing in reservoirs with different pore structures. The better the pore structure is, the lower the irreducible water saturation is; the higher the gas-phase relative permeability of irreducible water is, the more easily the gas reservoir can be developed. At the late stage of development, the residual gas is sealed in reservoirs in the forms of bypass, cutoff and dead end. In various reservoirs, the interference between gas and water is stronger, so gas and water tends to be produced simultaneously. The sealed gas may reduce the production rate of gas wells significantly, and the existence of water phase may reduce the gas permeability greatly; consequently, the water-bearing low-permeability tight sandstone gas reservoirs reveal serious water production, highly-difficult development and low-recovery percentage at the late stage, which have adverse impacts on the effective production and development of gas wells.

APPLICATION OF WELL LOG ANALYSIS IN ASSESSMENT OF PETROPHYSICAL PARAMETERS AND RESERVOIR CHARACTERIZATION OF WELLS IN THE “OTH” FIELD, ANAMBRA BASIN, SOUTHERN NIGERIA

Directory of Open Access Journals (Sweden)

Eugene URORO

2014-12-01

Full Text Available Over the past years, the Anambra basin one of Nigeria’s inland basins has recorded significant level of hydrocarbon exploration activities. The basin has been confirmed by several authors from source rock analyses to have the potential for generating hydrocarbon. For the hydrocarbon to be exploited, it is imperative to have a thorough understanding of the reservoir. Computer-assisted log analyses were employed to effectively evaluate the petrophysical parameters such as the shale volume (Vsh, total porosity (TP, effective porosity (EP, water saturation (Sw, and hydrocarbon saturation (Sh. Cross-plots of the petrophysical parameters versus depth were illustrated. Five hydrocarbon bearing reservoirs were delineated in well 1, four in well 2. The reservoirs in well 3 do not contain hydrocarbon. The estimated reservoir porosity varies from 10% to 21% while their permeability values range from 20md to 1400md. The porosity and permeability values suggest that reservoirs are good enough to store and also permit free flow of fluid. The volume of shale (0.05% to 0.35% analysis reveals that the reservoirs range from shaly sand to slightly shaly sand to clean sand reservoir. On the basis of petrophysics data, the reservoirs are interpreted a good quality reservoir rocks which has been confirmed with high effective porosity range between 20% and high hydrocarbon saturation exceeding 55% water saturation in well 1 and well 2. Water saturation 3 is nearly 100% although the reservoir properties are good.  

EXPLOITATION AND OPTIMIZATION OF RESERVOIR PERFORMANCE IN HUNTON FORMATION, OKLAHOMA

Energy Technology Data Exchange (ETDEWEB)

Mohan Kelkar

2004-10-01

West Carney field--one of the newest fields discovered in Oklahoma--exhibits many unique production characteristics. These characteristics include: (1) decreasing water-oil ratio; (2) decreasing gas-oil ratio followed by an increase; (3) poor prediction capability of the reserves based on the log data; and (4) low geological connectivity but high hydrodynamic connectivity. The purpose of this investigation is to understand the principal mechanisms affecting the production, and propose methods by which we can extend the phenomenon to other fields with similar characteristics. In our experimental investigation section, we present the data on surfactant injection in near well bore region. We demonstrate that by injecting the surfactant, the relative permeability of water could be decreased, and that of gas could be increased. This should result in improved gas recovery from the reservoir. Our geological analysis of the reservoir develops the detailed stratigraphic description of the reservoir. Two new stratigraphic units, previously unrecognized, are identified. Additional lithofacies are recognized in new core descriptions. Our engineering analysis has determined that well density is an important parameter in optimally producing Hunton reservoirs. It appears that 160 acre is an optimal spacing. The reservoir pressure appears to decline over time; however, recovery per well is only weakly influenced by the pressure. This indicates that additional opportunity to drill wells exists in relatively depleted fields. A simple material balance technique is developed to validate the recovery of gas, oil and water. This technique can be used to further extrapolate recoveries from other fields with similar field characteristics.

Economics of Developing Hot Stratigraphic Reservoirs

Energy Technology Data Exchange (ETDEWEB)

Greg Mines; Hillary Hanson; Rick Allis; Joseph Moore

2014-09-01

Stratigraphic geothermal reservoirs at 3 – 4 km depth in high heat-flow basins are capable of sustaining 100 MW-scale power plants at about 10 c/kWh. This paper examines the impacts on the levelized cost of electricity (LCOE) of reservoir depth and temperature, reservoir productivity, and drillhole/casing options. For a reservoir at 3 km depth with a moderate productivity index by hydrothermal reservoir standards (about 50 L/s/MPa, 5.6 gpm/psi), an LCOE of 10c/kWh requires the reservoir to be at about 200°C. This is the upper temperature limit for pumps. The calculations assume standard hydrothermal drilling costs, with the production interval completed with a 7 inch liner in an 8.5 inch hole. If a reservoir at 4 km depth has excellent permeability characteristics with a productivity index of 100 L/s/MPa (11.3 gpm/psi), then the LCOE is about 11 c/kWh assuming the temperature decline rate with development is not excessive (< 1%/y, with first thermal breakthrough delayed by about 10 years). Completing wells with modest horizontal legs (e.g. several hundred meters) may be important for improving well productivity because of the naturally high, sub-horizontal permeability in this type of reservoir. Reducing the injector/producer well ratio may also be cost-effective if the injectors are drilled as larger holes.

Detecting fluid leakage of a reservoir dam based on streaming self-potential measurements

Science.gov (United States)

Song, Seo Young; Kim, Bitnarae; Nam, Myung Jin; Lim, Sung Keun

2015-04-01

Between many reservoir dams for agriculture in suburban area of South Korea, water leakage has been reported several times. The dam under consideration in this study, which is located in Gyeong-buk, in the south-east of the Korean Peninsula, was reported to have a large leakage at the right foot of downstream side of the reservoir dam. For the detection of the leakage, not only geological survey but also geophysical explorations have been made for precision safety diagnosis, since the leakage can lead to dam failure. Geophysical exploration includes both electrical-resistivity and self-potential surveys, while geological surveys water permeability test, standard penetration test, and sampling for undisturbed sample during the course of the drilling investigation. The geophysical explorations were made not only along the top of dam but also transverse the heel of dam. The leakage of water installations can change the known-heterogeneous structure of the dam body but also cause streaming spontaneous (self) potential (SP) anomaly, which can be detected by electrical resistivity and SP measurements, respectively. For the interpretation of streaming SP, we used trial-and-error method by comparing synthetic SP data with field SP data for model update. For the computation, we first invert the resistivity data to obtain the distorted resistivity structure of the dam levee then make three-dimensional electrical-resistivity modeling for the streaming potential distribution of the dam levee. Our simulation algorithm of streaming SP distribution based on the integrated finite difference scheme computes two-dimensional (2D) SP distribution based on the distribution of calculated flow velocities of fluid for a given permeability structure together with physical properties. This permeability is repeatedly updated based on error between synthetic and field SP data, until the synthetic data match the field data. Through this trial-and-error-based SP interpretation, we locate the

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.

Analysis of fracture patterns and local stress field variations in fractured reservoirs

Science.gov (United States)

Deckert, Hagen; Drews, Michael; Fremgen, Dominik; Wellmann, J. Florian

2010-05-01

A meaningful qualitative evaluation of permeabilities in fractured reservoirs in geothermal or hydrocarbon industry requires the spatial description of the existing discontinuity pattern within the area of interest and an analysis how these fractures might behave under given stress fields. This combined information can then be used for better estimating preferred fluid pathway directions within the reservoir, which is of particular interest for defining potential drilling sites. A description of the spatial fracture pattern mainly includes the orientation of rock discontinuities, spacing relationships between single fractures and their lateral extent. We have examined and quantified fracture patterns in several outcrops of granite at the Costa Brava, Spain, and in the Black Forest, Germany, for describing reservoir characteristics. For our analysis of fracture patterns we have used photogrammetric methods to create high-resolution georeferenced digital 3D images of outcrop walls. The advantage of this approach, compared to conventional methods for fracture analysis, is that it provides a better 3D description of the fracture geometry as the entity of position, extent and orientation of single fractures with respect to their surrounding neighbors is conserved. Hence for instance, the method allows generating fracture density maps, which can be used for a better description of the spatial distribution of discontinuities in a given outcrop. Using photogrammetric techniques also has the advantage to acquire very large data sets providing statistically sound results. To assess whether the recorded discontinuities might act as fluid pathways information on the stress field is needed. A 3D model of the regional tectonic structure was created and the geometry of the faults was put into a mechanical 3D Boundary Element (BE) Model. The model takes into account the elastic material properties of the geological units and the orientation of single fault segments. The

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.

Optimisation of decision making under uncertainty throughout field lifetime: A fractured reservoir example

Science.gov (United States)

Arnold, Dan; Demyanov, Vasily; Christie, Mike; Bakay, Alexander; Gopa, Konstantin

2016-10-01

Assessing the change in uncertainty in reservoir production forecasts over field lifetime is rarely undertaken because of the complexity of joining together the individual workflows. This becomes particularly important in complex fields such as naturally fractured reservoirs. The impact of this problem has been identified in previous and many solutions have been proposed but never implemented on complex reservoir problems due to the computational cost of quantifying uncertainty and optimising the reservoir development, specifically knowing how many and what kind of simulations to run. This paper demonstrates a workflow that propagates uncertainty throughout field lifetime, and into the decision making process by a combination of a metric-based approach, multi-objective optimisation and Bayesian estimation of uncertainty. The workflow propagates uncertainty estimates from appraisal into initial development optimisation, then updates uncertainty through history matching and finally propagates it into late-life optimisation. The combination of techniques applied, namely the metric approach and multi-objective optimisation, help evaluate development options under uncertainty. This was achieved with a significantly reduced number of flow simulations, such that the combined workflow is computationally feasible to run for a real-field problem. This workflow is applied to two synthetic naturally fractured reservoir (NFR) case studies in appraisal, field development, history matching and mid-life EOR stages. The first is a simple sector model, while the second is a more complex full field example based on a real life analogue. This study infers geological uncertainty from an ensemble of models that are based on the carbonate Brazilian outcrop which are propagated through the field lifetime, before and after the start of production, with the inclusion of production data significantly collapsing the spread of P10-P90 in reservoir forecasts. The workflow links uncertainty

Optical investigation of effective permeability of dilute magnetic dielectrics with magnetic field

Science.gov (United States)

Banerjee, Ananya; Sarkar, A.

2016-05-01

The prime objective of this paper is to investigate the magnetic nature of dilute magnetic dielectrics (DMD) under variation of external magnetic field. The said variation is studied over developed nano-sized Gadolinium Oxide as a DMD system. The observed experimental field variation of the effective magnetic permeability is analyzed results of optical experiment. The experiment records the variation of Brewster angle of incident polarized LASER beam from the surface of developed DMD specimen with applied out of plane external magnetic field. The effective refractive index and hence relative magnetic permeability were estimated following electro-magnetic theory. The overall results obtained and agreement between theory and experiment are good.

Optical investigation of effective permeability of dilute magnetic dielectrics with magnetic field

Energy Technology Data Exchange (ETDEWEB)

Banerjee, Ananya, E-mail: banerjee.ananya2008@gmail.com; Sarkar, A. [Dept. of Physics, Bijoy Krishna Girls’ College, 5/3 M.G. Road, Howrah 711101, W.B. (India)

2016-05-06

The prime objective of this paper is to investigate the magnetic nature of dilute magnetic dielectrics (DMD) under variation of external magnetic field. The said variation is studied over developed nano-sized Gadolinium Oxide as a DMD system. The observed experimental field variation of the effective magnetic permeability is analyzed results of optical experiment. The experiment records the variation of Brewster angle of incident polarized LASER beam from the surface of developed DMD specimen with applied out of plane external magnetic field. The effective refractive index and hence relative magnetic permeability were estimated following electro-magnetic theory. The overall results obtained and agreement between theory and experiment are good.

Stress concentrations at structural discontinuities in active fault zones in the western United States: Implications for permeability and fluid flow in geothermal fields

Science.gov (United States)

Siler, Drew; Hinz, Nicholas H.; Faulds, James E.

2018-01-01

Slip can induce concentration of stresses at discontinuities along fault systems. These structural discontinuities, i.e., fault terminations, fault step-overs, intersections, bends, and other fault interaction areas, are known to host fluid flow in ore deposition systems, oil and gas reservoirs, and geothermal systems. We modeled stress transfer associated with slip on faults with Holocene-to-historic slip histories at the Salt Wells and Bradys geothermal systems in western Nevada, United States. Results show discrete locations of stress perturbation within discontinuities along these fault systems. Well field data, surface geothermal manifestations, and subsurface temperature data, each a proxy for modern fluid circulation in the fields, indicate that geothermal fluid flow is focused in these same areas where stresses are most highly perturbed. These results suggest that submeter- to meter-scale slip on these fault systems generates stress perturbations that are sufficiently large to promote slip on an array of secondary structures spanning the footprint of the modern geothermal activity. Slip on these secondary faults and fractures generates permeability through kinematic deformation and allows for transmission of fluids. Still, mineralization is expected to seal permeability along faults and fractures over time scales that are generally shorter than either earthquake recurrence intervals or the estimated life span of geothermal fields. This suggests that though stress perturbations resulting from fault slip are broadly important for defining the location and spatial extent of enhanced permeability at structural discontinuities, continual generation and maintenance of flow conduits throughout these areas are probably dependent on the deformation mechanism(s) affecting individual structures.

A reservoir engineering assessment of the San Jacinto-Tizate Geothermal Field, Nicaragua

Energy Technology Data Exchange (ETDEWEB)

Ostapenko, S.; Spektor, S.; Davila, H.; Porras, E.; Perez, M.

1996-01-24

More than twenty yews have passed since geothermal research and drilling took place at the geothermal fields in Nicaragua- Tbe well horn Momotombo Geothermal Field (70 We) has been generating electricity since 1983, and now a new geothermal field is under exploration. the San Jacinto-Tizate. Two reservoirs hydraulic connected were found. The shallow reservoir (270°C) at the depth of 550 - 1200 meters, and the deep one at > 1600 meters. Both of theme are water dominated reservoirs, although a two phase condition exist in the upper part of the shallow one. Different transient tests and a multi-well interference test have been carried out, very high transmissivity value were estimated around the well SJ-4 and average values for the others. A preliminar conceptual model of the geothermal system is given in this paper, as the result of the geology, geophysics, hydrology studies, drilling and reservoir evaluation.

Major occurrences and reservoir concepts of marine clathrate hydrates: Implications of field evidence

Science.gov (United States)

Booth, J.S.; Winters, W.J.; Dillon, William P.; Clennell, M.B.; Rowe, M.M.

1998-01-01

This paper is part of the special publication Gas hydrates: relevance to world margin stability and climatic change (eds J.P. Henriet and J. Mienert). Questions concerning clathrate hydrate as an energy resource, as a factor in modifying global climate and as a triggering mechanism for mass movements invite consideration of what factors promote hydrate concentration, and what the quintessential hydrate-rich sediment may be. Gas hydrate field data, although limited, provide a starting point for identifying the environments and processes that lead to more massive concentrations. Gas hydrate zones are up to 30 m thick and the vertical range of occurrence at a site may exceed 200 m. Zones typically occur more than 100m above the phase boundary. Thicker zones are overwhelmingly associated with structural features and tectonism, and often contain sand. It is unclear whether an apparent association between zone thickness and porosity represents a cause-and-effect relationship. The primary control on the thickness of a potential gas hydrate reservoir is the geological setting. Deep water and low geothermal gradients foster thick gas hydrate stability zones (GHSZs). The presence of faults, fractures, etc. can favour migration of gas-rich fluids. Geological processes, such as eustacy or subsidence, may alter the thickness of the GHSZ or affect hydrate concentratiion. Tectonic forces may promote injection of gas into the GHSZ. More porous and permeable sediment, as host sediment properties, increase storage capacity and fluid conductivity, and thus also enhance reservoir potential.

Geologic and engineering characterization of Geraldine Ford field, Reeves and Culberson Counties, Texas. Topical report -- 1997

Energy Technology Data Exchange (ETDEWEB)

Dutton, S.P.; Malik, M.A.; Asquith, G.B.; Barton, M.D.; Cole, A.G.; Gogas, J.; Clift, S.J.; Guzman, J.I.

1998-04-01

The objective of this Class III project is to demonstrate that detailed reservoir characterization of clastic reservoirs in basinal sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost-effective way to recover more of the original oil in place by strategic infill-well placement and geologically based field development. The study focused on Geraldine Ford field, which produces from the upper Bell Canyon formation (Ramsey sandstone). Petrophysical characterization of the Ford Geraldine unit was accomplished by integrating core and log data and quantifying petrophysical properties from wireline logs. The petrophysical data were used to map porosity, permeability, net pay, water saturation, mobile oil saturation, and other reservoir properties. Once the reservoir-characterization study was completed, a demonstration area of approximately 1 mi{sup 2} in the northern part of the unit was chosen for reservoir modeling/simulation. A quarter of a five-spot injection pattern in the demonstration area was selected for flow simulations, and two cases of permeability distribution were considered, one using stochastic permeability distribution generated by conditional simulation and the other using layered permeabilities. Flow simulations were performed using UTCOMP, an isothermal, three-dimensional, compositional simulator for miscible gas flooding. Results indicate that 10--30% (1 to 3 MMbbl) of remaining oil in place in the demonstration area can be produced by CO{sub 2} injection.

Improvements in scaling of counter-current imbibition recovery curves using a shape factor including permeability anisotropy

Science.gov (United States)

Abbasi, Jassem; Sarafrazi, Shiva; Riazi, Masoud; Ghaedi, Mojtaba

2018-02-01

Spontaneous imbibition is the main oil production mechanism in the water invaded zone of a naturally fractured reservoir (NFR). Different scaling equations have been presented in the literature for upscaling of core scale imbibition recovery curves to field scale matrix blocks. Various scale dependent parameters such as gravity effects and boundary influences are required to be considered in the upscaling process. Fluid flow from matrix blocks to the fracture system is highly dependent on the permeability value in the horizontal and vertical directions. The purpose of this study is to include permeability anisotropy in the available scaling equations to improve the prediction of imbibition assisted oil production in NFRs. In this paper, a commercial reservoir simulator was used to obtain imbibition recovery curves for different scenarios. Then, the effect of permeability anisotropy on imbibition recovery curves was investigated, and the weakness of the existing scaling equations for anisotropic rocks was demonstrated. Consequently, an analytical shape factor was introduced that can better scale all the curves related to anisotropic matrix blocks.

Potential Development of Hydrocarbon in Basement Reservoirs In Indonesia

Directory of Open Access Journals (Sweden)

D. Sunarjanto

2014-07-01

Full Text Available DOI: 10.17014/ijog.v8i3.165Basement rocks, in particular igneous and metamorphic rocks are known to have porosity and permeability which should not be ignored. Primary porosity of basement rocks occurs as the result of rock formation. The porosity increases by the presence of cracks occurring as the result of tectonic processes (secondary porosity. Various efforts have been carried out to explore hydrocarbon in basement rocks. Some oil and gas fields proved that the basement rocks are as reservoirs which so far have provided oil and gas in significant amount. A review using previous research data, new data, and observation of igneous rocks in some fields has been done to see the development of exploration and basement reservoirs in Indonesia. A review on terminology of basement rock up till the identification of oil and gas exploration in basement rocks need to be based on the latest technology. An environmental approach is suggested to be applied as an alternative in analyzing the policy on oil and gas exploration development, especially in basement reservoirs.

Stress- and Chemistry-Mediated Permeability Enhancement/Degradation in Stimulated Critically-Stressed Fractures

Energy Technology Data Exchange (ETDEWEB)

Derek Elsworth; Abraham S. Grader; Chris Marone; Phillip Halleck; Peter Rose; Igor Faoro; Joshua Taron; André Niemeijer; Hideaki Yasuhara

2009-03-30

This work has investigated the interactions between stress and chemistry in controlling the evolution of permeability in stimulated fractured reservoirs through an integrated program of experimentation and modeling. Flow-through experiments on natural and artificial fractures in Coso diorite have examined the evolution of permeability under paths of mean and deviatoric stresses, including the role of dissolution and precipitation. Models accommodating these behaviors have examined the importance of incorporating the complex couplings between stress and chemistry in examining the evolution of permeability in EGS reservoirs. This document reports the findings of experiment [1,2] and analysis [3,4], in four sequential chapters.

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.

Effect of temperature on sandstone permeability

DEFF Research Database (Denmark)

Rosenbrand, Esther; Kjøller, Claus

Hot water injection in geothermal sandstone aquifers is considered for seasonal energy storage in Denmark. However, an increase in the aquifer temperature might reduce permeability, and thereby increase production costs. An understanding of the factors that control permeability is required in order...... and the Klinkenberg procedure showed the expected correlation between the two measures, however, differences could be around one order of magnitude. In tight gas sandstones, permeability is often sensitive to net stress, which might change due to the pore pressure change in the Klinkenberg procedure. Besides...... affecting the Klinkenberg procedure, the combined effect of slip and changes in permeability would affect production during pressure depletion in tight gas sandstone reservoirs; therefore effects of gas slip and net stress on permeability were combined in a model based on the Klinkenberg equation. A lower...

Combined geophysical, geochemical and geological investigations of geothermal reservoir characteristics in Lower Saxony, Germany

Science.gov (United States)

Hahne, B.; Thomas, R.

2012-04-01

The North German basin provides a significant geothermal potential, although temperature gradients are moderate. However, deep drilling up to several thousand meters is required to reach temperatures high enough for efficient generation of geothermal heat and electric power. In these depths we have not much information yet about relevant physical properties like porosity or permeability of the rock formations. Therefore the costs of developing a geothermal reservoir and the risk of missing the optimum drilling location are high. The collaborative research association "Geothermal Energy and High Performance Drilling" (gebo) unites several universities and research institutes in Lower Saxony, Germany. It aims at a significant increase of economic efficiency by introducing innovative technology and high tech materials resisting temperatures up to 200 °C in the drilling process. Furthermore, a better understanding of the geothermal reservoir is essential. gebo is structured into four main fields: Drilling Technology, Materials, Technical Systems and Geosystem. Here, we show the combined work of the Geosystem group, which focuses on the exploration of geological fault zones as a potential geothermal reservoir as well as on modeling the stress field, heat transport, coupled thermo-hydro-mechanical processes, geochemical interactions and prediction of the long-term behavior of the reservoir. First results include combined seismic and geoelectric images of the Leinetalgraben fault system, a comparison of seismic images from P- and S-wave measurements, mechanical properties of North German rocks from field and laboratory measurements as well as from drill cores, seismological characterization of stimulated reservoirs, a thermodynamic "gebo" database for modeling hydrogeochemical processes in North German formation waters with high salinity and at high temperatures, stress models for specific sites in northern Germany, and modeling results of permeability and heat transport

Integrated Reservoir Modeling of CO2-EOR Performance and Storage Potential in the Farnsworth Field Unit, Texas.

Science.gov (United States)

Ampomah, W.; Balch, R. S.; Cather, M.; Dai, Z.

2017-12-01

We present a performance assessment methodology and storage potential for CO2 enhanced oil recovery (EOR) in partially depleted reservoirs. A three dimensional heterogeneous reservoir model was developed based on geological, geophysics and engineering data from Farnsworth field Unit (FWU). The model aided in improved characterization of prominent rock properties within the Pennsylvanian aged Morrow sandstone reservoir. Seismic attributes illuminated previously unknown faults and structural elements within the field. A laboratory fluid analysis was tuned to an equation of state and subsequently used to predict the thermodynamic minimum miscible pressure (MMP). Datasets including net-to-gross ratio, volume of shale, permeability, and burial history were used to model initial fault transmissibility based on Sperivick model. An improved history match of primary and secondary recovery was performed to set the basis for a CO2 flood study. The performance of the current CO2 miscible flood patterns was subsequently calibrated to historical production and injection data. Several prediction models were constructed to study the effect of recycling, addition of wells and /or new patterns, water alternating gas (WAG) cycles and optimum amount of CO2 purchase on incremental oil production and CO2 storage in the FWU. The history matching study successfully validated the presence of the previously undetected faults within FWU that were seen in the seismic survey. The analysis of the various prediction scenarios showed that recycling a high percentage of produced gas, addition of new wells and a gradual reduction in CO2 purchase after several years of operation would be the best approach to ensure a high percentage of recoverable incremental oil and sequestration of anthropogenic CO2 within the Morrow reservoir. Larger percentage of stored CO2 were dissolved in residual oil and less amount existed as supercritical free CO2. The geomechanical analysis on the caprock proved to an

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

Predicting carbonate permeabilities from wireline logs using a back-propagation neural network

International Nuclear Information System (INIS)

Wiener, J.M.; Moll, R.F.; Rogers, J.A.

1991-01-01

This paper explores the applicability of using Neural Networks to aid in the determination of carbonate permeability from wireline logs. Resistivity, interval transit time, neutron porosity, and bulk density logs form Texaco's Stockyard Creek Oil field were used as input to a specially designed neural network to predict core permeabilities in this carbonate reservoir. Also of interest was the comparison of the neural network's results to those of standard statistical techniques. The process of developing the neural network for this problem has shown that a good understanding of the data is required when creating the training set from which the network learns. This network was trained to learn core permeabilities from raw and transformed log data using a hyperbolic tangent transfer function and a sum of squares global error function. Also, it required two hidden layers to solve this particular problem

Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs :

Energy Technology Data Exchange (ETDEWEB)

Gardner, William Payton

2013-06-01

The purpose of this study is to develop an engineering and operational understanding of CAES performance for a depleted natural gas reservoir by evaluation of relative permeability effects of air, water and natural gas in depleted natural gas reservoirs as a reservoir is initially depleted, an air bubble is created, and as air is initially cycled. The composition of produced gases will be evaluated as the three phase flow of methane, nitrogen and brine are modeled. The effects of a methane gas phase on the relative permeability of air in a formation are investigated and the composition of the produced fluid, which consists primarily of the amount of natural gas in the produced air are determined. Simulations of compressed air energy storage (CAES) in depleted natural gas reservoirs were carried out to assess the effect of formation permeability on the design of a simple CAES system. The injection of N2 (as a proxy to air), and the extraction of the resulting gas mixture in a depleted natural gas reservoir were modeled using the TOUGH2 reservoir simulator with the EOS7c equation of state. The optimal borehole spacing was determined as a function of the formation scale intrinsic permeability. Natural gas reservoir results are similar to those for an aquifer. Borehole spacing is dependent upon the intrinsic permeability of the formation. Higher permeability allows increased injection and extraction rates which is equivalent to more power per borehole for a given screen length. The number of boreholes per 100 MW for a given intrinsic permeability in a depleted natural gas reservoir is essentially identical to that determined for a simple aquifer of identical properties. During bubble formation methane is displaced and a sharp N2methane boundary is formed with an almost pure N2 gas phase in the bubble near the borehole. During cycling mixing of methane and air occurs along the boundary as the air bubble boundary moves. The extracted gas mixture changes as a

A Simple Approach to Dynamic Material Balance in Gas-Condensate Reservoirs

Directory of Open Access Journals (Sweden)

Heidari Sureshjani M.

2013-02-01

Full Text Available In traditional material balance calculations, shut-in well pressure data are used to determine average reservoir pressure while recent techniques do not require the well to be shut-in and use instead flowing well pressure-rate data. These methods, which are known as “dynamic” material balance, are developed for single-phase flow (oil or gas in reservoirs. However, utilization of such methods for gas-condensate reservoirs may create significant errors in prediction of average reservoir pressure due to violation of the single-phase assumption in such reservoirs. In a previous work, a method for production data analysis in gas-condensate reservoirs was developed. The method required standard gas production rate, producing gas-oil ratio, flowing well pressure, CVD data and relative permeability curves. This paper presents a new technique which does not need relative permeability curves and flowing well pressure. In this method, the producing oil-gas ratio is interpolated in the vaporized oil in gas phase (Rv versus pressure (p data in the CVD table and the corresponding pressure is located. The parameter pressure/two-phase deviation factor (p/ztp is then evaluated at the determined pressure points and is plotted versus produced moles (np which forms a straight line. The nature of this plot is such that its extrapolation to point where p/ztp = 0 will give initial moles in place. Putting initial pressure/initial two-phase deviation factor (pi/ztp,i (known parameter and estimated initial moles (ni into the material balance equation, average reservoir pressure can be determined. A main assumption behind the method is that the region where both gas and condensate phases are mobile is of negligible size compared to the reservoir. The approach is quite simple and calculations are much easier than the previous work. It provides a practical engineering tool for industry studies as it requires data which are generally available in normal production

Analysis of Fault Permeability Using Mapping and Flow Modeling, Hickory Sandstone Aquifer, Central Texas

Energy Technology Data Exchange (ETDEWEB)

Nieto Camargo, Jorge E., E-mail: jorge.nietocamargo@aramco.com; Jensen, Jerry L., E-mail: jjensen@ucalgary.ca [University of Calgary, Department of Chemical and Petroleum Engineering (Canada)

2012-09-15

Reservoir compartments, typical targets for infill well locations, are commonly created by faults that may reduce permeability. A narrow fault may consist of a complex assemblage of deformation elements that result in spatially variable and anisotropic permeabilities. We report on the permeability structure of a km-scale fault sampled through drilling a faulted siliciclastic aquifer in central Texas. Probe and whole-core permeabilities, serial CAT scans, and textural and structural data from the selected core samples are used to understand permeability structure of fault zones and develop predictive models of fault zone permeability. Using numerical flow simulation, it is possible to predict permeability anisotropy associated with faults and evaluate the effect of individual deformation elements in the overall permeability tensor. We found relationships between the permeability of the host rock and those of the highly deformed (HD) fault-elements according to the fault throw. The lateral continuity and predictable permeability of the HD fault elements enhance capability for estimating the effects of subseismic faulting on fluid flow in low-shale reservoirs.

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.

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

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.

Effect of Matrix-Wellbore Flow and Porosity on Pressure Transient Response in Shale Formation Modeling by Dual Porosity and Dual Permeability System

Directory of Open Access Journals (Sweden)

Daolun Li

2015-01-01

Full Text Available A mathematical dual porosity and dual permeability numerical model based on perpendicular bisection (PEBI grid is developed to describe gas flow behaviors in shale-gas reservoirs by incorporating slippage corrected permeability and adsorbed gas effect. Parametric studies are conducted for a horizontal well with multiple infinite conductivity hydraulic fractures in shale-gas reservoir to investigate effect of matrix-wellbore flow, natural fracture porosity, and matrix porosity. We find that the ratio of fracture permeability to matrix permeability approximately decides the bottom hole pressure (BHP error caused by omitting the flow between matrix and wellbore and that the effect of matrix porosity on BHP is related to adsorption gas content. When adsorbed gas accounts for large proportion of the total gas storage in shale formation, matrix porosity only has a very small effect on BHP. Otherwise, it has obvious influence. This paper can help us understand the complex pressure transient response due to existence of the adsorbed gas and help petroleum engineers to interpret the field data better.

Porosity, petrophysics and permeability of the Whitby Mudstone (UK)

Science.gov (United States)

Houben, M.; Barnhoorn, A.; Hardebol, N.; Ifada, M.; Boersma, Q.; Douma, L.; Peach, C. J.; Bertotti, G.; Drury, M. R.

2016-12-01

Typically pore diameters in shales range from the µm down to the nm scale and the effective permeability of shale reservoirs is a function of the interconnectivity between the pore space and the natural fracture network present. The length and spacing of mechanical induced and natural fractures is one of the factors controlling gas produtivity from unconventional reservoirs. Permeability of the Whitby Mudstone measured on 1 inch cores was linked to microstructure and combined with natural fracture spacing present in outcrops along the Yorkshire coast (UK) to get insight into possible fluid pathways from reservoir to well. We used a combination of different techniques to characterize the porosity (gas adsorption, Scanning Electron Microscopy), mineralogy (X-Ray Fluorescence, X-Ray Diffraction, Scanning Electron Microscopy) and permeability (pressure step decay) of the Whitby Mudstone. In addition, we mapped the natural fracture network as present in outcrops along the Yorkshire coast (UK) at the 10-2-101m scale. Mineralogically we are dealing with a rock that is high in clay content and has an average organic matter content of about 10%. Results show a low porosity (max. 7%) as well as low permeability for the Whitby Mudstone. The permeability, measured parallel to bedding, depends on the confining pressure and is 86 nanodarcy at 10 MPa effective confining pressure and decreases to 16 nanodarcy at 40 MPa effective confining pressure. At the scale of observation the average distance to nearest natural fracture is in the order of 0.13 meter and 90 percent of all matrix elements are spaced within 0.4 meter to the nearest fracture. By assuming darcy flow, a permeability of 100 nanodarcy and 10% of overpressure we calculated that for the Whitby mudstone most of the gas resides in the matrix for less than 60 days until it reaches the fracture network.

Hot and Steamy Fractures in the Philippines: The Geological Characterization and Permeability Evaluation of Fractures in the Southern Negros Geothermal Field, Philippines

Science.gov (United States)

Pastoriza, L. R.; Holdsworth, R.; McCaffrey, K. J. W.; Dempsey, E. D.; Walker, R. J.; Gluyas, J.; Reyes, J. K.

2016-12-01

Fluid flow pathway characterization is critical to geothermal exploration and exploitation. It requires a good understanding of the structural evolution, fault distribution and fluid flow properties. A dominantly fieldwork-based approach has been used to evaluate the potential fracture permeability characteristics of a typical high-temperature geothermal reservoir in the Southern Negros Geothermal Field, Philippines. This is a liquid-dominated geothermal resource hosted in the andesitic to dacitic Quaternary Cuernos de Negros Volcano in Negros Island. Fieldwork reveals two main fracture groups based on fault rock characteristics, alteration type, relative age of deformation, and associated thermal manifestation, with the younger fractures mainly related to the development of the modern geothermal system. Palaeostress analyses of cross-cutting fault and fracture arrays reveal a progressive counterclockwise rotation of stress axes from the (?)Pliocene up to the present-day, which is consistent with the regional tectonic models. A combined slip and dilation tendency analysis of the mapped faults indicates that NW-SE structures should be particularly promising drilling targets. Frequency versus length and aperture plots of fractures across six to eight orders of magnitude show power-law relationships with a change in scaling exponent in the region of 100 to 500m length-scales. Finally, evaluation of the topology of the fracture branches shows the dominance of Y-nodes that are mostly doubly connected suggesting good connectivity and permeability within the fracture networks. The results obtained in this study illustrate the value of methods that can be globally applied during exploration to better characterize fracture systems in geothermal reservoirs using multiscale datasets.

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.

Integration of rock typing methods for carbonate reservoir characterization

International Nuclear Information System (INIS)

Aliakbardoust, E; Rahimpour-Bonab, H

2013-01-01

Reservoir rock typing is the most important part of all reservoir modelling. For integrated reservoir rock typing, static and dynamic properties need to be combined, but sometimes these two are incompatible. The failure is due to the misunderstanding of the crucial parameters that control the dynamic behaviour of the reservoir rock and thus selecting inappropriate methods for defining static rock types. In this study, rock types were defined by combining the SCAL data with the rock properties, particularly rock fabric and pore types. First, air-displacing-water capillary pressure curues were classified because they are representative of fluid saturation and behaviour under capillary forces. Next the most important rock properties which control the fluid flow and saturation behaviour (rock fabric and pore types) were combined with defined classes. Corresponding petrophysical properties were also attributed to reservoir rock types and eventually, defined rock types were compared with relative permeability curves. This study focused on representing the importance of the pore system, specifically pore types in fluid saturation and entrapment in the reservoir rock. The most common tests in static rock typing, such as electrofacies analysis and porosity–permeability correlation, were carried out and the results indicate that these are not appropriate approaches for reservoir rock typing in carbonate reservoirs with a complicated pore system. (paper)

Static and Dynamic Reservoir Characterization Using High Resolution P-Wave Velocity Data in Delhi Field, la

Science.gov (United States)

Hussain, S.; Davis, T.

2012-12-01

Static and dynamic reservoir characterization was done on high resolution P-wave seismic data in Delhi Field, LA to study the complex stratigraphy of the Holt-Bryant sands and to delineate the CO2 flow path. The field is undergoing CO2 injection for enhanced oil recovery. The seismic data was bandwidth extended by Geotrace to decrease the tuning thickness effect. Once the authenticity of the added frequencies in the data was determined, the interpretation helped map thin Tuscaloosa and Paluxy sands. Cross-equalization was done on the baseline and monitor surveys to remove the non-repeatable noise in the data. Acoustic impedance (AI) inversion was done on the baseline and monitor surveys to map the changes in AI with CO2 injection in the field. Figure 1 shows the AI percentage change at Base Paluxy. The analysis helped identify areas that were not being swept by CO2. Figure 2 shows the CO2 flow paths in Tuscaloosa formation. The percentage change of AI with CO2 injection and pressure increase corresponded with the fluid substitution modeling results. Time-lapse interpretation helped in delineating the channels, high permeability zones and the bypassed zones in the reservoir.; Figure 1: P-impedance percentage difference map with a 2 ms window centered at the base of Paluxy with the production data from June 2010 overlain; the black dashed line is the oil-water contact; notice the negative impedance change below the OWC. The lighter yellow color shows area where Paluxy is not being swept completely. ; Figure 2: P-impedance percentage difference map at TUSC 7 top; the white triangles are TUSC 7 injectors and the white circles are TUSC 7 producers; the black polygons show the flow paths of CO2.

Improved prediction of reservoir behavior through integration of quantitative geological and petrophysical data

Energy Technology Data Exchange (ETDEWEB)

Auman, J. B.; Davies, D. K.; Vessell, R. K.

1997-08-01

Methodology that promises improved reservoir characterization and prediction of permeability, production and injection behavior during primary and enhanced recovery operations was demonstrated. The method is based on identifying intervals of unique pore geometry by a combination of image analysis techniques and traditional petrophysical measurements to calculate rock type and estimate permeability and saturation. Results from a complex carbonate and sandstone reservoir were presented as illustrative examples of the versatility and high level of accuracy of this method in predicting reservoir quality. 16 refs., 5 tabs., 14 figs.

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.

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.

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

Effects of Collar Permeability on the Field Quality of the Large Aperture Quadrupoles for the LHC

CERN Document Server

Catalan-Lasheras, N; Kirby, G; Mess, K H; Ostojic, R; Russenschuck, Stephan

2008-01-01

The LHC contains a number of large aperture quadrupoles (MQY) in the insertions. The acceptance of these magnets was based on warm magnetic measurements performed before delivery to CERN. During the series production of the MQY quadrupoles, the permeability of the collars drifted from the nominal value, and effects on the transfer function and multipole components became evident. To study the effects on the magnetic field, variable permeability of the stainless-steel collars as a function of local field and temperature was introduced into a numerical model. Comparing the results with measured data, we could isolate the contribution of permeability deviation on the magnetic field quality. The extrapolation of transfer function and field multipoles to operating temperature and current gives the necessary offsets, which are compared with measurements on a reduced set of magnets.

An asymptotic model of seismic reflection from a permeable layer

Energy Technology Data Exchange (ETDEWEB)

Silin, D.; Goloshubin, G.

2009-10-15

Analysis of compression wave propagation in a poroelastic medium predicts a peak of reflection from a high-permeability layer in the low-frequency end of the spectrum. An explicit formula expresses the resonant frequency through the elastic moduli of the solid skeleton, the permeability of the reservoir rock, the fluid viscosity and compressibility, and the reservoir thickness. This result is obtained through a low-frequency asymptotic analysis of Biot's model of poroelasticity. A review of the derivation of the main equations from the Hooke's law, momentum and mass balance equations, and Darcy's law suggests an alternative new physical interpretation of some coefficients of the classical poroelasticity. The velocity of wave propagation, the attenuation factor, and the wave number, are expressed in the form of power series with respect to a small dimensionless parameter. The absolute value of this parameter is equal to the product of the kinematic reservoir fluid mobility and the wave frequency. Retaining only the leading terms of the series leads to explicit and relatively simple expressions for the reflection and transmission coefficients for a planar wave crossing an interface between two permeable media, as well as wave reflection from a thin highly-permeable layer (a lens). Practical applications of the obtained asymptotic formulae are seismic modeling, inversion, and at-tribute analysis.

Reservoir characterization of the Mt. Simon Sandstone, Illinois Basin, USA

Science.gov (United States)

Frailey, S.M.; Damico, J.; Leetaru, H.E.

2011-01-01

The integration of open hole well log analyses, core analyses and pressure transient analyses was used for reservoir characterization of the Mt. Simon sandstone. Characterization of the injection interval provides the basis for a geologic model to support the baseline MVA model, specify pressure design requirements of surface equipment, develop completion strategies, estimate injection rates, and project the CO2 plume distribution.The Cambrian-age Mt. Simon Sandstone overlies the Precambrian granite basement of the Illinois Basin. The Mt. Simon is relatively thick formation exceeding 800 meters in some areas of the Illinois Basin. In the deeper part of the basin where sequestration is likely to occur at depths exceeding 1000 m, horizontal core permeability ranges from less than 1 ?? 10-12 cm 2 to greater than 1 ?? 10-8 cm2. Well log and core porosity can be up to 30% in the basal Mt. Simon reservoir. For modeling purposes, reservoir characterization includes absolute horizontal and vertical permeability, effective porosity, net and gross thickness, and depth. For horizontal permeability, log porosity was correlated with core. The core porosity-permeability correlation was improved by using grain size as an indication of pore throat size. After numerous attempts to identify an appropriate log signature, the calculated cementation exponent from Archie's porosity and resistivity relationships was used to identify which porosity-permeability correlation to apply and a permeability log was made. Due to the relatively large thickness of the Mt. Simon, vertical permeability is an important attribute to understand the distribution of CO2 when the injection interval is in the lower part of the unit. Only core analyses and specifically designed pressure transient tests can yield vertical permeability. Many reservoir flow models show that 500-800 m from the injection well most of the CO2 migrates upward depending on the magnitude of the vertical permeability and CO2 injection

Interwell tracer analyses of a hydraulically fractured granitic geothermal reservoir

International Nuclear Information System (INIS)

Tester, J.W.; Potter, R.M.; Bivins, R.L.

1979-01-01

Field experiments using fluorescent dye and radioactive tracers (Br 82 and I 131 ) have been employed to characterize a hot, low-matrix permeability, hydraulically-fractured granitic reservoir at depths of 2440 to 2960 m (8000 to 9700 ft). Tracer profiles and residence time distributions have been used to delineate changes in the fracture system, particularly in diagnosing pathological flow patterns and in identifying new injection and production zones. The effectiveness of one- and two-dimensional theoretical dispersion models utilizing single and multiple porous, fractured zones with velocity and formation dependent effects are discussed with respect to actual field data

Comprehensive Understanding of the Zipingpu Reservoir to the Ms8.0 Wenchuan Earthquake

Science.gov (United States)

Cheng, H.; Pang, Y. J.; Zhang, H.; Shi, Y.

2014-12-01

After the Wenchuan earthquake occurred, whether the big earthquake triggered by the storage of the Zipingpu Reservoir has attracted wide attention in international academic community. In addition to the qualitative discussion, many scholars also adopted the quantitative analysis methods to calculate the stress changes, but due to the different results, they draw very different conclusions. Here, we take the dispute of different teams in the quantitative calculation of Zipingpu reservoir as a starting point. In order to find out the key influence factors of quantitative calculation and know about the existing uncertainty elements during the numerical simulation, we analyze factors which may cause the differences. The preliminary results show that the calculation methods (analytical method or numerical method), dimension of models (2-D or 3-D), diffusion model, diffusion coefficient and focal mechanism are the main factors resulted in the differences, especially the diffusion coefficient of the fractured rock mass. The change of coulomb failure stress of the epicenter of Wenchuan earthquake attained from 2-D model is about 3 times of that of 3-D model. And it is not reasonable that only considering the fault permeability (assuming the permeability of rock mass as infinity) or only considering homogeneous isotropic rock mass permeability (ignoring the fault permeability). The different focal mechanisms also could dramatically affect the change of coulomb failure stress of the epicenter of Wenchuan earthquake, and the differences can research 2-7 times. And the differences the change of coulomb failure stress can reach several hundreds times, when selecting different diffusion coefficients. According to existing research that the magnitude of coulomb failure stress change is about several kPa, we could not rule out the possibility that the Zipingpu Reservoir may trigger the 2008 Wenchuan earthquake. However, for the background stress is not clear and coulomb failure

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

The overall objective of this project was to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involved improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective has been to transfer technology that can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The first budget period addressed several producibility problems in the Tar II-A and Tar V thermal recovery operations that are common in SBC reservoirs. A few of the advanced technologies developed include a three-dimensional (3-D) deterministic geologic model, a 3-D deterministic thermal reservoir simulation model to aid in reservoir management and subsequent post-steamflood development work, and a detailed study on the geochemical interactions between the steam and the formation rocks and fluids. State of the art operational work included drilling and performing a pilot steam injection and production project via four new horizontal wells (2 producers and 2 injectors), implementing a hot water alternating steam (WAS) drive pilot in the existing steamflood area to improve thermal efficiency, installing a 2400-foot insulated, subsurface harbor channel crossing to supply steam to an island location, testing a novel alkaline steam completion technique to control well sanding problems, and starting on an advanced reservoir management system through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation. The second budget period phase (BP2) continued to implement state-of-the-art operational work to optimize thermal recovery processes, improve well drilling and completion practices, and evaluate the

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)

Gasbuggy reservoir evaluation - 1969 report

International Nuclear Information System (INIS)

Atkinson, C.H.; Ward, Don C.; Lemon, R.F.

1970-01-01

The December 10, 1967, Project Gasbuggy nuclear detonation followed the drilling and testing of two exploratory wells which confirmed reservoir characteristics and suitability of the site. Reentry and gas production testing of the explosive emplacement hole indicated a collapse chimney about 150 feet in diameter extending from the 4,240-foot detonation depth to about 3,900 feet, the top of the 300-foot-thick Pictured Cliffs gas sand. Production tests of the chimney well in the summer of 1968 and during the last 12 months have resulted in a cumulative production of 213 million cubic feet of hydrocarbons, and gas recovery in 20 years is estimated to be 900 million cubic feet, which would be an increase by a factor of at least 5 over estimated recovery from conventional field wells in this low permeability area. At the end of production tests the flow rate was 160,000 cubic feet per day, which is 6 to 7 times that of an average field well in the area. Data from reentry of a pre-shot test well and a new postshot well at distances from the detonation of 300 and 250 feet, respectively, indicate low productivity and consequently low permeability in any fractures at these locations. (author)

Gasbuggy reservoir evaluation - 1969 report

Energy Technology Data Exchange (ETDEWEB)

Atkinson, C H; Ward, Don C [Bureau of Mines, U.S. Department of the Interior (United States); Lemon, R F [El Paso Natural Gas Company (United States)

1970-05-01

The December 10, 1967, Project Gasbuggy nuclear detonation followed the drilling and testing of two exploratory wells which confirmed reservoir characteristics and suitability of the site. Reentry and gas production testing of the explosive emplacement hole indicated a collapse chimney about 150 feet in diameter extending from the 4,240-foot detonation depth to about 3,900 feet, the top of the 300-foot-thick Pictured Cliffs gas sand. Production tests of the chimney well in the summer of 1968 and during the last 12 months have resulted in a cumulative production of 213 million cubic feet of hydrocarbons, and gas recovery in 20 years is estimated to be 900 million cubic feet, which would be an increase by a factor of at least 5 over estimated recovery from conventional field wells in this low permeability area. At the end of production tests the flow rate was 160,000 cubic feet per day, which is 6 to 7 times that of an average field well in the area. Data from reentry of a pre-shot test well and a new postshot well at distances from the detonation of 300 and 250 feet, respectively, indicate low productivity and consequently low permeability in any fractures at these locations. (author)

Reservoir characterization using artificial neural network; Neural network wo mochiita choryuso tokusei kaiseki

Energy Technology Data Exchange (ETDEWEB)

Shimada, N; Kozawa, T [Japan National Oil Corp., Tokyo (Japan); Nishikawa, N; Tani, A [Fuji Research Institute Corp., Tokyo (Japan)

1997-05-27

Neural network is used for the prediction of porosity and permeability using logging data as reservoir characteristics, and the validity of this method is verified. For the prediction of reservoir characteristics by the use of seismic survey data, composite seismic survey records obtained by density logging and acoustic logging are used to experiment the prediction of porosity and permeability continuous along lines of wells. A 3-output back propagation network is used for analysis. There is a possibility that this technique when optimized will improve on prediction accuracy. Furthermore, in the case of characteristics mapping, 3-dimensional seismic data is applied to a carbonate rock reservoir for predicting spatial porosity and permeability. This technique facilitates the comprehensive analysis of core data, well data, and seismic survey data, enabling the derivation of a high-precision spatial distribution of reservoir characteristics. Efforts will continue for further improvement on prediction accuracy. 6 refs., 7 figs., 3 tabs.

Hot and steamy fractures in the Philippines: the characterisation and permeability evaluation of fractures of the Southern Negros Geothermal Field, Negros Oriental, Philippines

Science.gov (United States)

Pastoriza, Loraine; Holdsworth, Robert; McCaffrey, Kenneth; Dempsey, Eddie; Walker, Richard; Gluyas, Jon; Reyes, Jonathan

2017-04-01

Fluid flow pathway characterisation is critical to geothermal exploration and exploitation. It requires a good understanding of the structural evolution, fault distribution and fluid flow properties. A dominantly fieldwork-based approach has been used to evaluate the potential fracture permeability characteristics of a typical high-temperature geothermal reservoir in the Southern Negros Geothermal Field, Philippines. This is a liquid-dominated geothermal resource hosted in the andesitic to dacitic Quaternary Cuernos de Negros Volcano in Negros Island. Fieldwork reveals two main fracture groups based on fault rock characteristics, alteration type, relative age of deformation, and associated thermal manifestation, with the younger fractures mainly related to the development of the modern geothermal system. Palaeostress analyses of cross-cutting fault and fracture arrays reveal a progressive counterclockwise rotation of stress axes from the (?)Pliocene up to the present-day, which is consistent with the regional tectonic models. A combined slip and dilation tendency analysis of the mapped faults indicates that NW-SE structures should be particularly promising drilling targets. Frequency versus length and aperture plots of fractures across six to eight orders of magnitude show power-law relationships with a change in scaling exponent in the region of 100 to 500m length-scales. Finally, evaluation of the topology of the fracture branches shows the dominance of Y-nodes that are mostly doubly connected suggesting good connectivity and permeability within the fracture networks. The results obtained in this study illustrate the value of methods that can be globally applied during exploration to better characterize fracture systems in geothermal reservoirs using multiscale datasets.

Sensitivity Analysis of Methane Hydrate Reservoirs: Effects of Reservoir Parameters on Gas Productivity and Economics

Science.gov (United States)

Anderson, B. J.; Gaddipati, M.; Nyayapathi, L.

2008-12-01

This paper presents a parametric study on production rates of natural gas from gas hydrates by the method of depressurization, using CMG STARS. Seven factors/parameters were considered as perturbations from a base-case hydrate reservoir description based on Problem 7 of the International Methane Hydrate Reservoir Simulator Code Comparison Study led by the Department of Energy and the USGS. This reservoir is modeled after the inferred properties of the hydrate deposit at the Prudhoe Bay L-106 site. The included sensitivity variables were hydrate saturation, pressure (depth), temperature, bottom-hole pressure of the production well, free water saturation, intrinsic rock permeability, and porosity. A two-level (L=2) Plackett-Burman experimental design was used to study the relative effects of these factors. The measured variable was the discounted cumulative gas production. The discount rate chosen was 15%, resulting in the gas contribution to the net present value of a reservoir. Eight different designs were developed for conducting sensitivity analysis and the effects of the parameters on the real and discounted production rates will be discussed. The breakeven price in various cases and the dependence of the breakeven price on the production parameters is given in the paper. As expected, initial reservoir temperature has the strongest positive effect on the productivity of a hydrate deposit and the bottom-hole pressure in the production well has the strongest negative dependence. Also resulting in a positive correlation is the intrinsic permeability and the initial free water of the formation. Negative effects were found for initial hydrate saturation (at saturations greater than 50% of the pore space) and the reservoir porosity. These negative effects are related to the available sensible heat of the reservoir, with decreasing productivity due to decreasing available sensible heat. Finally, we conclude that for the base case reservoir, the break-even price (BEP

Exploration and reservoir characterization; Technology Target Areas; TTA2 - Exploration and reservoir characterisation

Energy Technology Data Exchange (ETDEWEB)

2008-07-01

In future, research within exploration and reservoir characterization will play an even more important role for Norway since resources are decreasing and new challenges like deep sea, harsh environment and last but not least environmental issues have to be considered. There are two major fields which have to be addressed within exploration and reservoir characterization: First, replacement of reserves by new discoveries and ultimate field recoveries in mature basins at the Norwegian Continental shelf, e.g. at the Halten Terrace has to be addressed. A wealth of data exists in the more mature areas. Interdisciplinary integration is a key feature of reservoir characterization, where available data and specialist knowledge need to be combined into a consistent reservoir description. A systematic approach for handling both uncertainties in data sources and uncertainties in basic models is needed. Fast simulation techniques are necessary to generate models spanning the event space, covering both underground based and model-based uncertainties. Second, exploration in frontier areas like the Barents Sea region and the deeper Voering Basin has to be addressed. The scarcity of wells in these frontier areas leads to uncertainties in the geological understanding. Basin- and depositional modelling are essential for predicting where source rocks and reservoir rocks are deposited, and if, when and which hydrocarbons are generated and trapped. Predictive models and improved process understanding is therefore crucial to meet these issues. Especially the challenges related to the salt deposits e.g. sub-salt/sub-basalt reservoir definitions in the Nordkapp Basin demands up-front research and technology developments. TTA2 stresses the need to focus on the development of new talents. We also see a strong need to push cooperation as far as possible in the present competitive environment. Projects that may require a substantial financial commitment have been identified. The following

Reservoir compartmentalization and management strategies: Lessons learned in the Illinois basin

Energy Technology Data Exchange (ETDEWEB)

Grube, J.P.; Crockett, J.E.; Huff, B.G. [and others

1997-08-01

A research project jointly sponsored by the US Department of Energy and the Illinois State Geological Survey focused on the Cypress and Aux Vases Formations (Mississippian), major clastic reservoirs in the Illinois Basin. Results from the research showed that understanding the nature and distribution of reservoir compartments, and using effective reservoir management strategies, can significantly improve recovery efficiencies from oil fields in this mature basin. Compartments can be most effectively drained where they are geologically well defined and reservoir management practices are coordinated through unified, compartment-wide, development programs. Our studies showed that the Cypress and Aux Vases reservoirs contain lateral and vertical permeability barriers forming compartments that range in size from isolated, interlaminated sandstone and shale beds to sandstone bodies tens of feet in thickness and more than a mile in length. Stacked or shingled, genetically similar sandstone bodies are commonly separated by thin impermeable intervals that can be difficult to distinguish on logs and can, therefore, cause correlation problems, even between wells drilled on spacing of less than ten acres. Lateral separation of sandstone bodies causes similar problems. Reservoir compartmentalization reduces primary and particularly secondary recovery by trapping pockets of by-passed or banked oil. Compartments can be detected by comparing recovery factors of genetically similar sandstone bodies within a field; using packers to separate commingled intervals and analyzing fluid recoveries and pressures; making detailed core-to-log calibrations that identify compartment boundaries; and analyzing pressure data from waterflood programs.

Compositional and Relative Permeability Hysteresis Effects on Near-Miscible WAG

DEFF Research Database (Denmark)

Christensen, Jes Reimer; Stenby, Erling Halfdan; Skauge, Arne

1998-01-01

Evaluation of compositional effects and fluid flow description on near-miscible (water-alternating-gas) WAG modeling have been studied for a North Sea oil field starting production in 1998. A sector model with four wells was applied to simulate a heterogeneous sandstone reservoir, and a compositi......Evaluation of compositional effects and fluid flow description on near-miscible (water-alternating-gas) WAG modeling have been studied for a North Sea oil field starting production in 1998. A sector model with four wells was applied to simulate a heterogeneous sandstone reservoir......, and a compositional model was used to compare different production strategies e.g. waterflooding and a near-miscible (WAG) injection. In the WAG scheme both dry and wet (rich) hydrocarbon gases have been considered for injection. The phase behaviour was quantified by comparing the performance of the different...... injection gases. Result obtained shows the WAG injection gives improved recovery compared to water injection, due to better sweep and lower residual oil saturation. Simulations with and without relative permeability hysteresis (two-phase model) were compared. The effect of trapped gas on oil recovery does...

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.

Analysis of heterogeneous characteristics in a geothermal area with low permeability and high temperature

Directory of Open Access Journals (Sweden)

Alfonso Aragón-Aguilar

2017-09-01

Full Text Available An analytical methodology for reservoir characterization was applied in the central and southwestern zones of Los Humeros geothermal field (LHGF. This study involves analysis of temperature, pressure, enthalpy and permeability in wells and their distribution along the area. The wells located in the central western side of the geothermal field are productive, whereas those located at the central-eastern side are non-productive. Through temperature profiles, determined at steady state in the analyzed wells, it was observed that at bottom conditions (approximately 2300 m depth, temperatures vary between 280 and 360 °C. The temperatures are higher at the eastern side of central zone of LHGF. A review of transient pressure tests, laboratory measurements of core samples, and correlation of circulation losses during drilling suggest that permeability of the formation is low. The enthalpy behavior in productive wells shows a tendency of increase in the steam fraction. It was found that productivity behavior has inverse relation with permeability of rock formation. Further, it is observed that an imbalance exists between exploitation and recharge. It is concluded from the results that the wells located at central-eastern area have low permeability and high temperature, which indicates possibility of heat storage.

Avo analysis in the high impedance reservoir of Chuchupa Field

International Nuclear Information System (INIS)

Cediel Mauricio; Almanza Ovidio; Montes Luis

2012-01-01

The technique of bright spot as a direct indicator of hydrocarbons has been widely used since the work of Ostrander (1984), particularly in gas fields. Located at north of Colombia, the Chuchupa field has produced gas continuously during 30 years, but despite the coverage with 2D seismic, amplitude anomalies associated with gas accumulation have not been observed. In order to find the relationships between the amplitude information and the gas accumulation, an AVO analysis was performed to describe the seismic reservoir response. The raw data of a 2D seismic line that crosses the field from East to West and a well log data set were used. In a first approach the seismic response was modeled using well logs, so a comparative analysis between the furnished synthetic seismograms and the real CDP gathers was done. The results indicated that the reservoirs top is represented by a low amplitude peak which decreases when the offset increases but whose phase remains unchanged. In the well, where the reservoir has 100% gas saturation, a high correlation between the synthetic and real CDP gathers was observed. In a second approach, anomalous clustered points in the IV quadrant were discriminated through intercept versus gradient cross plot analysis. A weak Class-I anomaly was identified, which could not be observed in stacked sections and hence it should be analyzed using pre-stack data.

Wastewater injection and slip triggering: Results from a 3D coupled reservoir/rate-and-state model

Science.gov (United States)

Babazadeh, M.; Olson, J. E.; Schultz, R.

2017-12-01

Seismicity induced by fluid injection is controlled by parameters related to injection conditions, reservoir properties, and fault frictional behavior. We present results from a combined model that brings together injection physics, reservoir dynamics, and fault physics to better explain the primary controls on induced seismicity. We created a 3D fluid flow simulator using the embedded discrete fracture technique and then coupled it with a 3D displacement discontinuity model that uses rate and state friction to model slip events. The model is composed of three layers, including the top-seal, the injection reservoir, and the basement. Permeability is anisotropic (vertical vs horizontal) and along with porosity varies by layer. Injection control can be either rate or pressure. Fault properties include size, 2D permeability, and frictional properties. Several suites of simulations were run to evaluate the relative importance of each of the factors from all three parameter groups. We find that the injection parameters interact with the reservoir parameters in the context of the fault physics and these relations change for different reservoir and fault characteristics, leading to the need to examine the injection parameters only within the context of a particular faulted reservoir. For a reservoir with no flow boundaries, low permeability (5 md), and a fault with high fault-parallel permeability and critical stress, injection rate exerts the strongest control on magnitude and frequency of earthquakes. However, for a higher permeability reservoir (80 md), injection volume becomes the more important factor. Fault permeability structure is a key factor in inducing earthquakes in basement rocks below the injection reservoir. The initial failure state of the fault, which is challenging to assess, can have a big effect on the size and timing of events. For a fault 2 MPa below critical state, we were able to induce a slip event, but it occurred late in the injection history

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

An efficient permeability scaling-up technique applied to the discretized flow equations

Energy Technology Data Exchange (ETDEWEB)

Urgelli, D.; Ding, Yu [Institut Francais du Petrole, Rueil Malmaison (France)

1997-08-01

Grid-block permeability scaling-up for numerical reservoir simulations has been discussed for a long time in the literature. It is now recognized that a full permeability tensor is needed to get an accurate reservoir description at large scale. However, two major difficulties are encountered: (1) grid-block permeability cannot be properly defined because it depends on boundary conditions; (2) discretization of flow equations with a full permeability tensor is not straightforward and little work has been done on this subject. In this paper, we propose a new method, which allows us to get around both difficulties. As the two major problems are closely related, a global approach will preserve the accuracy. So, in the proposed method, the permeability up-scaling technique is integrated in the discretized numerical scheme for flow simulation. The permeability is scaled-up via the transmissibility term, in accordance with the fluid flow calculation in the numerical scheme. A finite-volume scheme is particularly studied, and the transmissibility scaling-up technique for this scheme is presented. Some numerical examples are tested for flow simulation. This new method is compared with some published numerical schemes for full permeability tensor discretization where the full permeability tensor is scaled-up through various techniques. Comparing the results with fine grid simulations shows that the new method is more accurate and more efficient.

Reservoir management

International Nuclear Information System (INIS)

Satter, A.; Varnon, J.E.; Hoang, M.T.

1992-01-01

A reservoir's life begins with exploration leading to discovery followed by delineation of the reservoir, development of the field, production by primary, secondary and tertiary means, and finally to abandonment. Sound reservoir management is the key to maximizing economic operation of the reservoir throughout its entire life. Technological advances and rapidly increasing computer power are providing tools to better manage reservoirs and are increasing the gap between good and neural reservoir management. The modern reservoir management process involves goal setting, planning, implementing, monitoring, evaluating, and revising plans. Setting a reservoir management strategy requires knowledge of the reservoir, availability of technology, and knowledge of the business, political, and environmental climate. Formulating a comprehensive management plan involves depletion and development strategies, data acquisition and analyses, geological and numerical model studies, production and reserves forecasts, facilities requirements, economic optimization, and management approval. This paper provides management, engineers, geologists, geophysicists, and field operations staff with a better understanding of the practical approach to reservoir management using a multidisciplinary, integrated team approach

Reservoir management

International Nuclear Information System (INIS)

Satter, A.; Varnon, J.E.; Hoang, M.T.

1992-01-01

A reservoir's life begins with exploration leading to discovery followed by delineation of the reservoir, development of the field, production by primary, secondary and tertiary means, and finally to abandonment. Sound reservoir management is the key to maximizing economic operation of the reservoir throughout its entire life. Technological advances and rapidly increasing computer power are providing tools to better manage reservoirs and are increasing the gap between good and neutral reservoir management. The modern reservoir management process involves goal setting, planning, implementing, monitoring, evaluating, and revising plans. Setting a reservoir management strategy requires knowledge of the reservoir, availability of technology, and knowledge of the business, political, and environmental climate. Formulating a comprehensive management plan involves depletion and development strategies, data acquisition and analyses, geological and numerical model studies, production and reserves forecasts, facilities requirements, economic optimization, and management approval. This paper provides management, engineers geologists, geophysicists, and field operations staff with a better understanding of the practical approach to reservoir management using a multidisciplinary, integrated team approach

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

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.

Scale Model Simulation of Enhanced Geothermal Reservoir Creation

Science.gov (United States)

Gutierrez, M.; Frash, L.; Hampton, J.

2012-12-01

Geothermal energy technology has successfully provided a means of generating stable base load electricity for many years. However, implementation has been spatially limited to limited availability of high quality traditional hydro-thermal resources possessing the combination of a shallow high heat flow anomaly and an aquifer with sufficient permeability and continuous fluid recharge. Enhanced Geothermal Systems (EGS) has been proposed as a potential solution to enable additional energy production from the non-conventional hydro-thermal resources. Hydraulic fracturing is considered the primary means of creating functional EGS reservoirs at sites where the permeability of the rock is too limited to allow cost effective heat recovery. EGS reservoir creation requires improved fracturing methodology, rheologically controllable fracturing fluids, and temperature hardened proppants. Although large fracture volumes (several cubic km) have been created in the field, circulating fluid through these full volumes and maintaining fracture volumes have proven difficult. Stimulation technology and methodology as used in the oil and gas industry for sedimentary formations are well developed; however, they have not sufficiently been demonstrated for EGS reservoir creation. Insufficient data and measurements under geothermal conditions make it difficult to directly translate experience from the oil and gas industries to EGS applications. To demonstrate the feasibility of EGS reservoir creation and subsequent geothermal energy production, and to improve the understanding of hydraulic and propping in EGS reservoirs, a heated true-triaxial load cell with a high pressure fluid injection system was developed to simulate an EGS system from stimulation to production. This apparatus is capable of loading a 30x30x30 cubic cm rock sample with independent principal stresses up to 13 MPa while simultaneously providing heating up to 180 degree C. Multiple orientated boreholes of 5 to 10 mm

THMC Modeling of EGS Reservoirs -- Continuum through Discontinuum Representations. Capturing Reservoir Stimulation, Evolution and Induced Seismicity

Energy Technology Data Exchange (ETDEWEB)

Elsworth, Derek [Pennsylvania State Univ., State College, PA (United States); Izadi, Ghazal [Pennsylvania State Univ., State College, PA (United States); Gan, Quan [Pennsylvania State Univ., State College, PA (United States); Fang, Yi [Pennsylvania State Univ., State College, PA (United States); Taron, Josh [US Geological Survey, Menlo Park, CA (United States); Sonnenthal, Eric [Lawrence Berkeley National Lab. (LBNL), Berkeley, CA (United States)

2015-07-28

This work has investigated the roles of effective stress induced by changes in fluid pressure, temperature and chemistry in contributing to the evolution of permeability and induced seismicity in geothermal reservoirs. This work has developed continuum models [1] to represent the progress or seismicity during both stimulation [2] and production [3]. These methods have been used to resolve anomalous observations of induced seismicity at the Newberry Volcano demonstration project [4] through the application of modeling and experimentation. Later work then focuses on the occurrence of late stage seismicity induced by thermal stresses [5] including the codifying of the timing and severity of such responses [6]. Furthermore, mechanistic linkages between observed seismicity and the evolution of permeability have been developed using data from the Newberry project [7] and benchmarked against field injection experiments. Finally, discontinuum models [8] incorporating the roles of discrete fracture networks have been applied to represent stimulation and then thermal recovery for new arrangements of geothermal wells incorporating the development of flow manifolds [9] in order to increase thermal output and longevity in EGS systems.

Integrated Modeling and Carbonate Reservoir Analysis, Upper Jurassic Smackover Formation, Fishpond Field, Southwest Alabama

Science.gov (United States)

Owen, Alexander Emory

This field case study focuses on Upper Jurassic (Oxfordian) Smackover hydrocarbon reservoir characterization, modeling and evaluation at Fishpond Field, Escambia County, Alabama, eastern Gulf Coastal Plain of North America. The field is located in the Conecuh Embayment area, south of the Little Cedar Creek Field in Conecuh County and east of Appleton Field in Escambia County. In the Conecuh Embayment, Smackover microbial buildups commonly developed on Paleozoic basement paleohighs in an inner to middle carbonate ramp setting. The microbial and associated facies identified in Fishpond Field are: (F-1) peloidal wackestone, (F-2) peloidal packstone, (F-3) peloidal grainstone, (F-4) peloidal grainstone/packstone, (F-5) microbially-influenced wackestone, (F-6) microbially-influenced packstone, (F-7) microbial boundstone, (F-8) oolitic grainstone, (F-9) shale, and (F-10) dolomitized wackestone/packstone. The Smackover section consists of an alternation of carbonate facies, including F-1 through F-8. The repetitive vertical trend in facies indicates variations in depositional conditions in the area as a result of changes in water depth, energy conditions, salinity, and/or water chemistry due to temporal variations or changes in relative sea level. Accommodation for sediment accumulation also was produced by a change in base level due to differential movement of basement rocks as a result of faulting and/or subsidence due to burial compaction and extension. These changes in base level contributed to the development of a microbial buildup that ranges between 130-165 ft in thickness. The Fishpond Field carbonate reservoir includes a lower microbial buildup interval, a middle grainstone/packstone interval and an upper microbial buildup interval. The Fishpond Field has sedimentary and petroleum system characteristics similar to the neighboring Appleton and Little Cedar Creek Fields, but also has distinct differences from these Smackover fields. The characteristics of the

Analysis of influencing factors of production performance of enhanced geothermal system: A case study at Yangbajing geothermal field

International Nuclear Information System (INIS)

Zeng, Yuchao; Tang, Liansheng; Wu, Nengyou; Cao, Yifei

2017-01-01

Deep geological exploration indicates that there is a high-temperature fractured granite reservoir at depth of 950–1350 m in well ZK4001 in the north of Yangbajing geothermal field, with an average temperature of 248 °C and a pressure within 8.01–11.57 MPa. In this work we established a conceptual and numerical model of this granite reservoir, evaluated heat production and electricity generation potential from this fractured reservoir by means of numerical simulation, and analyzed main factors affecting the heat production performance. The results indicate that in the reference case the system attains an electric power of 29.5–25.1 MW, a reservoir impedance of 0.12–0.21MPa/(kg/s), a pump power of 0.7–1.6 MW and an energy efficiency of 41.1–15.7 during a 50 year period. Main factors affecting the electric power are water production rate and injection temperature. Main factors affecting the reservoir impedance are the reservoir permeability, the water production rate and the injection temperature. Main factors affecting the pump power are the reservoir permeability, the water production rate and the injection temperature. Main factors affecting the energy efficiency are the reservoir permeability, the water production rate and the injection temperature. Within certain ranges main measures to improve the reservoir performance are to increase the reservoir permeability or adopt more reasonable water production rate and injection temperature. - Highlights: • We established a numerical model of the 950–1350 m fractured granite reservoir. • Desirable electricity production performance can be obtained under suitable conditions. • The system attains an electric power of 29.5–25.1 MW with an efficiency of about 41.1–15.7. • Electric power mainly depends on water production rate and injection temperature. • Higher permeability within a certain range is favorable for electricity generation.

Investigation of hydraulic fracture re-orientation effects in tight gas reservoirs

Energy Technology Data Exchange (ETDEWEB)

Hagemann, B.; Wegner, J.; Ganzer, L. [Technische Univ. Clausthal, Clausthal-Zellerfeld (Germany). ITE

2013-08-01

permeability, influence the dimension and time development of the stress reversal region in this process. The success of re-orientated fractures depends on the actual dimension of the stress reversal region. The work demonstrates that COMSOL Multiphysics enables the simulation of stress reversal during depletion. The reservoir model can be extended and used to select candidate wells for re-fracturing treatments. Furthermore it helps predicting the optimum timing of re-fracturing in order to maximize production. The findings will support effective field development in tight gas reservoirs. (orig.)

Impact of Petrophysical Properties on Hydraulic Fracturing and Development in Tight Volcanic Gas Reservoirs

Directory of Open Access Journals (Sweden)

Yinghao Shen

2017-01-01

Full Text Available The volcanic reservoir is an important kind of unconventional reservoir. The aqueous phase trapping (APT appears because of fracturing fluids filtration. However, APT can be autoremoved for some wells after certain shut-in time. But there is significant distinction for different reservoirs. Experiments were performed to study the petrophysical properties of a volcanic reservoir and the spontaneous imbibition is monitored by nuclear magnetic resonance (NMR and pulse-decay permeability. Results showed that natural cracks appear in the samples as well as high irreducible water saturation. There is a quick decrease of rock permeability once the rock contacts water. The pores filled during spontaneous imbibition are mainly the nanopores from NMR spectra. Full understanding of the mineralogical effect and sample heterogeneity benefits the selection of segments to fracturing. The fast flow-back scheme is applicable in this reservoir to minimize the damage. Because lots of water imbibed into the nanopores, the main flow channels become larger, which are beneficial to the permeability recovery after flow-back of hydraulic fracturing. This is helpful in understanding the APT autoremoval after certain shut-in time. Also, Keeping the appropriate production differential pressure is very important in achieving the long term efficient development of volcanic gas reservoirs.

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.

A comparison between the pressure-lag model and the rate-type model for the prediction of reservoir compaction and surface subsidence

Energy Technology Data Exchange (ETDEWEB)

Smits, R.M.M.; De Waal, J.A.

1988-06-01

A theoretical study has been carried out to investigate whether the nonlinear compaction behavior of sandstone reservoirs, which has been reported for most well-documented field cases, can be explained by pressure lags in interbedding and/or neighboring low-permeability (shale) layers. On the basis of the results obtained, it is concluded that pressure-lag effects in normally encountered production scenarios cannot account for these nonlinearities, even under worst-case conditions. Therefore, the nonlinear field-compaction behavior must be caused by rate effects in the sandstone reservoir rock itself. This is supported by the fact that a rate-type compaction model recently introduced does indeed give a good description of the observed field behavior.

The geological model calibration - Learnings from integration of reservoir geology and field performance - Example from the upper carboniferous reservoirs of the Southern North Sea

NARCIS (Netherlands)

Moscariello, A.; Hoof, T.B. van; Kunakbayeva, G.; Veen, J.H. ten; Belt, F. van den; Twerda, A.; Peters, L.; Davis, P.; Williams, H.

2013-01-01

The Geological Model Calibration - Learnings from Integration of Reservoir Geology and Field Performance: example from the Upper Carboniferous Reservoirs of the Southern North Sea. Copyright © (2012) by the European Association of Geoscientists & Engineers All rights reserved.

Production induced boiling and cold water entry in the Cerro Prieto geothermal reservoir indicated by chemical and physical measurements

Energy Technology Data Exchange (ETDEWEB)

Grant, M.A. (DSIR, Wellington, New Zealand); Truesdell, A.H.; Manon, A.

1981-01-01

Chemical and physical data suggest that the relatively shallow western part of the Cerro Prieto reservoir is bounded below by low permeability rocks, and above and at the sides by an interface with cooler water. There is no continuous permeability barrier around or immediately above the reservoir. Permeability within the reservoir is dominantly intergranular. Mixture with cooler water rather than boiling is the dominant cooling process in the natural state, and production causes displacement of hot water by cooler water, not by vapor. Local boiling occurs near most wells in response to pressure decreases, but no general vapor zone has formed.

The reservoir properties of the upper Cretaceous productive deposits at the Pravoberezhnoe field. Kollektornyye svoystva verkhnemelovykh produktivnykh otlozheniy mestorozhdeniya Pravobeiezhnoye

Energy Technology Data Exchange (ETDEWEB)

Merkulov, A.V.; Yengibarov, V.N.

1984-01-01

Based on a set of various studies, an evaluation of the type of upper Cretaceous reservoir in the Pravoberezhnoe field is given. Compared to other fields in the Chechen Ingush Autonomous Soviet Socialist Republic, the upper Cretaceous productive deposits at this field are characterized by poorer reservoir properties. The set of all data indicates that the upper Cretaceous reservoir is analogous to reservoirs of equal age in existing fields in this republic and are cavernous fissured type.

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)

OPTIMIZATION OF INFILL DRILLING IN NATURALLY-FRACTURED TIGHT-GAS RESERVOIRS

Energy Technology Data Exchange (ETDEWEB)

Lawrence W. Teufel; Her-Yuan Chen; Thomas W. Engler; Bruce Hart

2004-05-01

A major goal of industry and the U.S. Department of Energy (DOE) fossil energy program is to increase gas reserves in tight-gas reservoirs. Infill drilling and hydraulic fracture stimulation in these reservoirs are important reservoir management strategies to increase production and reserves. Phase II of this DOE/cooperative industry project focused on optimization of infill drilling and evaluation of hydraulic fracturing in naturally-fractured tight-gas reservoirs. The cooperative project involved multidisciplinary reservoir characterization and simulation studies to determine infill well potential in the Mesaverde and Dakota sandstone formations at selected areas in the San Juan Basin of northwestern New Mexico. This work used the methodology and approach developed in Phase I. Integrated reservoir description and hydraulic fracture treatment analyses were also conducted in the Pecos Slope Abo tight-gas reservoir in southeastern New Mexico and the Lewis Shale in the San Juan Basin. This study has demonstrated a methodology to (1) describe reservoir heterogeneities and natural fracture systems, (2) determine reservoir permeability and permeability anisotropy, (3) define the elliptical drainage area and recoverable gas for existing wells, (4) determine the optimal location and number of new in-fill wells to maximize economic recovery, (5) forecast the increase in total cumulative gas production from infill drilling, and (6) evaluate hydraulic fracture simulation treatments and their impact on well drainage area and infill well potential. Industry partners during the course of this five-year project included BP, Burlington Resources, ConocoPhillips, and Williams.

Altering Reservoir Wettability to Improve Production from Single Wells

Energy Technology Data Exchange (ETDEWEB)

W. W. Weiss

2006-09-30

Many carbonate reservoirs are naturally fractured and typically produce less than 10% original oil in place during primary recovery. Spontaneous imbibition has proven an important mechanism for oil recovery from fractured reservoirs, which are usually weak waterflood candidates. In some situations, chemical stimulation can promote imbibition of water to alter the reservoir wettability toward water-wetness such that oil is produced at an economic rate from the rock matrix into fractures. In this project, cores and fluids from five reservoirs were used in laboratory tests: the San Andres formation (Fuhrman Masho and Eagle Creek fields) in the Permian Basin of Texas and New Mexico; and the Interlake, Stony Mountain, and Red River formations from the Cedar Creek Anticline in Montana and South Dakota. Solutions of nonionic, anionic, and amphoteric surfactants with formation water were used to promote waterwetness. Some Fuhrman Masho cores soaked in surfactant solution had improved oil recovery up to 38%. Most Eagle Creek cores did not respond to any of the tested surfactants. Some Cedar Creek anticline cores had good response to two anionic surfactants (CD 128 and A246L). The results indicate that cores with higher permeability responded better to the surfactants. The increased recovery is mainly ascribed to increased water-wetness. It is suspected that rock mineralogy is also an important factor. The laboratory work generated three field tests of the surfactant soak process in the West Fuhrman Masho San Andres Unit. The flawlessly designed tests included mechanical well clean out, installation of new pumps, and daily well tests before and after the treatments. Treatments were designed using artificial intelligence (AI) correlations developed from 23 previous surfactant soak treatments. The treatments were conducted during the last quarter of 2006. One of the wells produced a marginal volume of incremental oil through October. It is interesting to note that the field

A Rock Physics Feasibility Study of the Geothermal Gassum Reservoir, Copenhagen Area, Denmark

DEFF Research Database (Denmark)

Bredesen, Kenneth; Dalgaard, Esben Borch; Mathiesen, Anders

The subsurface of Denmark stores significant amounts of renewable geothermal energy which may contribute to domestic heating for centuries. However, establishing a successful geothermal plant with robust production capacity require reservoirs with sufficient high porosity and permeability. Modern...... quantitative seismic interpretation is a good approach to de-risk prospects and gain reservoir insight, but is so far not widely used for geothermal applications. In this study we perform a rock physics feasibility study as a pre-step towards quantitative seismic interpretation of geothermal reservoirs......, primarily in areas around Copenhagen. The results argue that it may be possible to use AVO and seismic inversion data to distinguish geothermal sandstone reservoirs from surrounding shales and to estimate porosity and permeability. Moreover, this study may represent new possibilities for future rock physics...

Reservoir simulation with MUFITS code: Extension for double porosity reservoirs and flows in horizontal wells

Science.gov (United States)

Afanasyev, Andrey

2017-04-01

Numerical modelling of multiphase flows in porous medium is necessary in many applications concerning subsurface utilization. An incomplete list of those applications includes oil and gas fields exploration, underground carbon dioxide storage and geothermal energy production. The numerical simulations are conducted using complicated computer programs called reservoir simulators. A robust simulator should include a wide range of modelling options covering various exploration techniques, rock and fluid properties, and geological settings. In this work we present a recent development of new options in MUFITS code [1]. The first option concerns modelling of multiphase flows in double-porosity double-permeability reservoirs. We describe internal representation of reservoir models in MUFITS, which are constructed as a 3D graph of grid blocks, pipe segments, interfaces, etc. In case of double porosity reservoir, two linked nodes of the graph correspond to a grid cell. We simulate the 6th SPE comparative problem [2] and a five-spot geothermal production problem to validate the option. The second option concerns modelling of flows in porous medium coupled with flows in horizontal wells that are represented in the 3D graph as a sequence of pipe segments linked with pipe junctions. The well completions link the pipe segments with reservoir. The hydraulics in the wellbore, i.e. the frictional pressure drop, is calculated in accordance with Haaland's formula. We validate the option against the 7th SPE comparative problem [3]. We acknowledge financial support by the Russian Foundation for Basic Research (project No RFBR-15-31-20585). References [1] Afanasyev, A. MUFITS Reservoir Simulation Software (www.mufits.imec.msu.ru). [2] Firoozabadi A. et al. Sixth SPE Comparative Solution Project: Dual-Porosity Simulators // J. Petrol. Tech. 1990. V.42. N.6. P.710-715. [3] Nghiem L., et al. Seventh SPE Comparative Solution Project: Modelling of Horizontal Wells in Reservoir Simulation

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.)

Inclusion of Topological Measurements into Analytic Estimates of Effective Permeability in Fractured Media

Science.gov (United States)

Sævik, P. N.; Nixon, C. W.

2017-11-01

We demonstrate how topology-based measures of connectivity can be used to improve analytical estimates of effective permeability in 2-D fracture networks, which is one of the key parameters necessary for fluid flow simulations at the reservoir scale. Existing methods in this field usually compute fracture connectivity using the average fracture length. This approach is valid for ideally shaped, randomly distributed fractures, but is not immediately applicable to natural fracture networks. In particular, natural networks tend to be more connected than randomly positioned fractures of comparable lengths, since natural fractures often terminate in each other. The proposed topological connectivity measure is based on the number of intersections and fracture terminations per sampling area, which for statistically stationary networks can be obtained directly from limited outcrop exposures. To evaluate the method, numerical permeability upscaling was performed on a large number of synthetic and natural fracture networks, with varying topology and geometry. The proposed method was seen to provide much more reliable permeability estimates than the length-based approach, across a wide range of fracture patterns. We summarize our results in a single, explicit formula for the effective permeability.

US production of natural gas from tight reservoirs

International Nuclear Information System (INIS)

1993-01-01

For the purposes of this report, tight gas reservoirs are defined as those that meet the Federal Energy Regulatory Commission's (FERC) definition of tight. They are generally characterized by an average reservoir rock permeability to gas of 0.1 millidarcy or less and, absent artificial stimulation of production, by production rates that do not exceed 5 barrels of oil per day and certain specified daily volumes of gas which increase with the depth of the reservoir. All of the statistics presented in this report pertain to wells that have been classified, from 1978 through 1991, as tight according to the FERC; i.e., they are ''legally tight'' reservoirs. Additional production from ''geologically tight'' reservoirs that have not been classified tight according to the FERC rules has been excluded. This category includes all producing wells drilled into legally designated tight gas reservoirs prior to 1978 and all producing wells drilled into physically tight gas reservoirs that have not been designated legally tight. Therefore, all gas production referenced herein is eligible for the Section 29 tax credit. Although the qualification period for the credit expired at the end of 1992, wells that were spudded (began to be drilled) between 1978 and May 1988, and from November 5, 1990, through year end 1992, are eligible for the tax credit for a subsequent period of 10 years. This report updates the EIA's tight gas production information through 1991 and considers further the history and effect on tight gas production of the Federal Government's regulatory and tax policy actions. It also provides some high points of the geologic background needed to understand the nature and location of low-permeability reservoirs

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.

Time-lapse cased hole reservoir evaluation based on the dual-detector neutron lifetime log: the CHES II approach

International Nuclear Information System (INIS)

DeVries, M.R.; Fertl, W.

1977-01-01

A newly developed cased hole analysis technique provides detailed information on (1) reservoir rock properties, such as porosity, shaliness, and formation permeability, (2) reservoir fluid saturation, (3) distinction of oil and gas pays, (4) state of reservoir depletion, such as cumulative hydrocarbon-feet at present time and cumulative hydrocarbon-feet already depleted (e.g., the sum of both values then giving the cumulative hydrocarbon-feet originally present), and (5) monitoring of hydrocarbon/water and gas/oil contacts behind pipe. The basic well log data required for this type of analysis include the Dual-Detector Neutron Lifetime Log, run in casing at any particular time in the life of a reservoir, and the initial open-hole resistivity log. In addition, porosity information from open-hole porosity log(s) or core data is necessary. Field examples from several areas are presented and discussed in the light of formation reservoir and hydrocarbon production characteristics

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.

Investigation on the effect of the reservoir variables and operational parameters on SAGD performance

Energy Technology Data Exchange (ETDEWEB)

Hashemi Kiasari, H.; Naderifar, A. [AmirKabir University of Technology, Tehran (Iran, Islamic Republic of). Petroleum Engineering Dept.; Sedaee Sola, B. [University of Tehran (Iran, Islamic Republic of). Faculty of Engineering. Inst. of Petroleum Engineering], e-mail: sedaeesola@yahoo.com

2010-04-15

Steam injection is the most important thermal enhanced oil recovery method. One typical procedure is Steam- Assisted Gravity Drainage (SAGD), which is a promising recovery process to produce heavy oil and bitumen. The method ensures a stable displacement of steam at economical rates by using gravity as the driving force and a pair of horizontal wells for injection/production. There are numerous studies done on SAGD in conventional reservoirs, but the majority of them focus on the investigation of the process in microscopic scale. In this study, we investigate the SAGD process with a preheating period, using steam circulation in well pair on a field scale. The synthetic homogenous model was constructed by CMG and simulated using the STARS module. The effects of operational parameters, such as preheating period, vertical well spacing, well pair length, steam quality and production pressure, and reservoir variables, such as rock porosity and permeability, vertical-to-horizontal permeability ratio, thermal conductivity of the formation and rock heat capacity, on the SAGD performance were investigated. The results show that the preheating period affects mainly the initial stages of production. Due to preheating, the well pair communication with the higher vertical distances is also established; therefore, there was no considerable difference between oil productions in various well spacing cases. As steam quality increases, the oil production in later production times also increases. At shorter well pair, more steam can be injected per unit length of well, but, on the other hand, the production well recovers less heated oil area; therefore the well pair length should be optimized in all cases. By decreasing the production well bottom-hole pressure, more heated oil in near well region is produced; therefore, the injected steam raises more in the depleted area. The results of the simulations show that very low permeability leads to a fully unsuccessful SAGD process. In the

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.

Field-scale forward and back diffusion through low-permeability zones

Science.gov (United States)

Yang, Minjune; Annable, Michael D.; Jawitz, James W.

2017-07-01

Understanding the effects of back diffusion of groundwater contaminants from low-permeability zones to aquifers is critical to making site management decisions related to remedial actions. Here, we combine aquifer and aquitard data to develop recommended site characterization strategies using a three-stage classification of plume life cycle based on the solute origins: aquifer source zone dissolution, source zone dissolution combined with back diffusion from an aquitard, and only back diffusion. We use measured aquitard concentration profile data from three field sites to identify signature shapes that are characteristic of these three stages. We find good fits to the measured data with analytical solutions that include the effects of advection and forward and back diffusion through low-permeability zones, and linearly and exponentially decreasing flux resulting from source dissolution in the aquifer. Aquifer contaminant time series data at monitoring wells from a mature site were well described using analytical solutions representing the combined case of source zone and back diffusion, while data from a site where the source had been isolated were well described solely by back diffusion. The modeling approach presented in this study is designed to enable site managers to implement appropriate remediation technologies at a proper timing for high- and low-permeability zones, considering estimated plume life cycle.

Reservoir computer predictions for the Three Meter magnetic field time evolution

Science.gov (United States)

Perevalov, A.; Rojas, R.; Lathrop, D. P.; Shani, I.; Hunt, B. R.

2017-12-01

The source of the Earth's magnetic field is the turbulent flow of liquid metal in the outer core. Our experiment's goal is to create Earth-like dynamo, to explore the mechanisms and to understand the dynamics of the magnetic and velocity fields. Since it is a complicated system, predictions of the magnetic field is a challenging problem. We present results of mimicking the three Meter experiment by a reservoir computer deep learning algorithm. The experiment is a three-meter diameter outer sphere and a one-meter diameter inner sphere with the gap filled with liquid sodium. The spheres can rotate up to 4 and 14 Hz respectively, giving a Reynolds number near to 108. Two external electromagnets apply magnetic fields, while an array of 31 external and 2 internal Hall sensors measure the resulting induced fields. We use this magnetic probe data to train a reservoir computer to predict the 3M time evolution and mimic waves in the experiment. Surprisingly accurate predictions can be made for several magnetic dipole time scales. This shows that such a complicated MHD system's behavior can be predicted. We gratefully acknowledge support from NSF EAR-1417148.

Development and application of 3-D fractal reservoir model based on collage theorem

Energy Technology Data Exchange (ETDEWEB)

Kim, I.K.; Kim, K.S.; Sung, W.M. [Hanyang Univ., Seoul (Korea, Republic of)

1995-04-30

Reservoir characterization is the essential process to accurately evaluate the reservoir and has been conducted by geostatistical method, SRA algorithm, and etc. The characterized distribution of heterogeneous property by these methods shows randomly distributed phenomena, and does not present anomalous shape of property variation at discontinued space as compared with the observed shape in nature. This study proposed a new algorithm of fractal concept based on collage theorem, which can virtually present not only geometric shape of irregular and anomalous pore structures or coastlines, but also property variation for discontinuously observed data. With a basis of fractal concept, three dimensional fractal reservoir model was developed to more accurately characterize the heterogeneous reservoir. We performed analysis of pre-predictable hypothetically observed permeability data by using the fractal reservoir model. From the results, we can recognize that permeability distributions in the areal view or the cross-sectional view were consistent with the observed data. (author). 8 refs., 1 tab., 6 figs.

A low-frequency asymptotic model of seismic reflection from a high-permeability layer

Energy Technology Data Exchange (ETDEWEB)

Silin, Dmitriy; Goloshubin, Gennady

2009-03-01

Analysis of compression wave propagation through a high-permeability layer in a homogeneous poroelastic medium predicts a peak of reflection in the low-frequency end of the spectrum. An explicit formula expresses the resonant frequency through the elastic moduli of the solid skeleton, the permeability of the reservoir rock, the fluid viscosity and compressibility, and the reservoir thickness. This result is obtained through a low-frequency asymptotic analysis of the Biot's model of poroelasticity. A new physical interpretation of some coefficients of the classical poroelasticity is a result of the derivation of the main equations from the Hooke's law, momentum and mass balance equations, and the Darcy's law. The velocity of wave propagation, the attenuation factor, and the wave number, are expressed in the form of power series with respect to a small dimensionless parameter. The latter is equal to the product of the kinematic reservoir fluid mobility, an imaginary unit, and the frequency of the signal. Retaining only the leading terms of the series leads to explicit and relatively simple expressions for the reflection and transmission coefficients for a planar wave crossing an interface between two permeable media, as well as wave reflection from a thin highly-permeable layer (a lens). The practical implications of the theory developed here are seismic modeling, inversion, and attribute analysis.

Fluid flow simulation and permeability computation in deformed porous carbonate grainstones

Science.gov (United States)

Zambrano, Miller; Tondi, Emanuele; Mancini, Lucia; Lanzafame, Gabriele; Trias, F. Xavier; Arzilli, Fabio; Materazzi, Marco; Torrieri, Stefano

2018-05-01

In deformed porous carbonates, the architecture of the pore network may be modified by deformation or diagenetic processes altering the permeability with respect to the pristine rock. The effects of the pore texture and morphology on permeability in porous rocks have been widely investigated due to the importance during the evaluation of geofluid reservoirs. In this study, these effects are assessed by combining synchrotron X-ray computed microtomography (SR micro-CT) and computational fluid dynamics. The studied samples pertain to deformed porous carbonate grainstones highly affected by deformation bands (DBs) exposed in Northwestern Sicily and Abruzzo regions, Italy. The high-resolution SR micro-CT images of the samples, acquired at the SYRMEP beamline of the Elettra - Sincrotrone Trieste laboratory (Italy), were used for simulating a pressure-driven flow by using the lattice-Boltzmann method (LBM). For the experiments, a multiple relaxation time (MRT) model with the D3Q19 scheme was used to avoid viscosity-dependent results of permeability. The permeability was calculated using Darcy's law once steady conditions were reached. After the simulations, the pore-network properties (effective porosity, specific surface area, and geometrical tortuosity) were calculated using 3D images of the velocity fields. These images were segmented considering a velocity threshold value higher than zero. The study showed that DBs may generate significant heterogeneity and anisotropy of the permeability of the evaluated rock samples. Cataclasis and cementation process taking place within the DBs reduce the effective porosity and therefore the permeability. Contrary to this, pressure dissolution and faulting may generate connected channels which contribute to the permeability only parallel to the DB.

Improving reservoir conformance using gelled polymer systems. Final report, September 25, 1992--July 31, 1996

Energy Technology Data Exchange (ETDEWEB)

Green, D.W.; Willhite, G.P.; Buller, C.; McCool, S.; Vossoughi, S.; Michnick, M.

1997-06-01

The objectives of the research program were to (1) identify and develop polymer systems which have potential to improve reservoir conformance of fluid displacement processes, (2) determine the performance of these systems in bulk and in porous media, and (3) develop methods to predict their performance in field applications. The research focused on four types of gel systems--KUSP1 systems that contain an aqueous polysaccharide designated KUSP1, phenolic-aldehyde systems composed of resorcinol and formaldehyde, colloidal-dispersion systems composed of polyacrylamide and aluminum citrate, and a chromium-based system where polyacrylamide is crosslinked by chromium(III). Gelation behavior of the resorcinol-formaldehyde systems and the KUSP1-borate system was examined. Size distributions of aggregates that form in the polyacrylamide-aluminum colloidal-dispersion gel system were determined. Permeabilities to brine of several rock materials were significantly reduced by gel treatments using the KUSP1 polymer-ester (monoethyl phthalate) system, the KUSP1 polymer-boric acid system, and the sulfomethylated resorcinol-formaldehyde system were also shown to significantly reduce the permeability to supercritical carbon dioxide. A mathematical model was developed to simulate the behavior of a chromium redox-polyacrylamide gel system that is injected through a wellbore into a multi-layer reservoir in which crossflow between layers is allowed. The model describes gelation kinetics and filtration of pre-gel aggregates in the reservoir. Studies using the model demonstrated the effect filtration of gel aggregates has on the placement of gel systems in layered reservoirs.

Structural and petrophysical characterization: from outcrop rock analogue to reservoir model of deep geothermal prospect in Eastern France

Science.gov (United States)

Bertrand, Lionel; Géraud, Yves; Diraison, Marc; Damy, Pierre-Clément

2017-04-01

The Scientific Interest Group (GIS) GEODENERGIES with the REFLET project aims to develop a geological and reservoir model for fault zones that are the main targets for deep geothermal prospects in the West European Rift system. In this project, several areas are studied with an integrated methodology combining field studies, boreholes and geophysical data acquisition and 3D modelling. In this study, we present the results of reservoir rock analogues characterization of one of these prospects in the Valence Graben (Eastern France). The approach used is a structural and petrophysical characterization of the rocks outcropping at the shoulders of the rift in order to model the buried targeted fault zone. The reservoir rocks are composed of fractured granites, gneiss and schists of the Hercynian basement of the graben. The matrix porosity, permeability, P-waves velocities and thermal conductivities have been characterized on hand samples coming from fault zones at the outcrop. Furthermore, fault organization has been mapped with the aim to identify the characteristic fault orientation, spacing and width. The fractures statistics like the orientation, density, and length have been identified in the damaged zones and unfaulted blocks regarding the regional fault pattern. All theses data have been included in a reservoir model with a double porosity model. The field study shows that the fault pattern in the outcrop area can be classified in different fault orders, with first order scale, larger faults distribution controls the first order structural and lithological organization. Between theses faults, the first order blocks are divided in second and third order faults, smaller structures, with characteristic spacing and width. Third order fault zones in granitic rocks show a significant porosity development in the fault cores until 25 % in the most locally altered material, as the damaged zones develop mostly fractures permeabilities. In the gneiss and schists units, the

Matrix acidification in carbonate reservoirs; Acidificacoes matriciais em reservatorios carbonaticos

Energy Technology Data Exchange (ETDEWEB)

Martins, Marcio de Oliveira [Petroleo Brasileiro S.A. (PETROBRAS), Rio de Janeiro, RJ (Brazil)

2012-07-01

Carbonate reservoirs are characterized by great diversity of its properties, including permeability and porosity. When submitted to matrix acidification, if no effort is employed, acid will tend to consume carbonates where permeability and porosity are higher, further increasing conductivity of these sites and also increasing permeability and porosity contrast existing before acid effects on formation. That would give limited production as result of small effective producer zone extent, with probable underutilization of potential reservoirs productivity. To overcome this effect and to achieve greater coverage of treatments, divergence techniques should be applied, including associations of them. This paper presents divergence techniques performed in matrix acidification of Campos and Espirito Santo basins wells, which represent great structural diversity and, as consequence, a significant range of situations. Formations tests results are analyzed to verify diversion systems effectiveness, and how they contribute to the growth of productive potential. (author)

Stress dependence of permeability of intact and fractured shale cores.

Science.gov (United States)

van Noort, Reinier; Yarushina, Viktoriya

2016-04-01

Whether a shale acts as a caprock, source rock, or reservoir, understanding fluid flow through shale is of major importance for understanding fluid flow in geological systems. Because of the low permeability of shale, flow is thought to be largely confined to fractures and similar features. In fracking operations, fractures are induced specifically to allow for hydrocarbon exploration. We have constructed an experimental setup to measure core permeabilities, using constant flow or a transient pulse. In this setup, we have measured the permeability of intact and fractured shale core samples, using either water or supercritical CO2 as the transporting fluid. Our measurements show decreasing permeability with increasing confining pressure, mainly due to time-dependent creep. Furthermore, our measurements show that for a simple splitting fracture, time-dependent creep will also eliminate any significant effect of this fracture on permeability. This effect of confinement on fracture permeability can have important implications regarding the effects of fracturing on shale permeability, and hence for operations depending on that.

Geological, Geophysical, And Thermal Characteristics Of The Salton Sea Geothermal Field, California

Energy Technology Data Exchange (ETDEWEB)

Younker, L.W.; Kasameyer, P. W.; Tewhey, J. D.

1981-01-01

The Salton Sea Geothermal Field is the largest water-dominated geothermal field in the Salton Trough in Southern California. Within the trough, local zones of extension among active right-stepping right-lateral strike-slip faults allow mantle-derived magmas to intrude the sedimentary sequence. The intrusions serves as heat sources to drive hydrothermal systems. We can characterize the field in detail because we have an extensive geological and geophysical data base. The sediments are relatively undeformed and can be divided into three categories as a function of depth: (1) low-permeability cap rock, (2) upper reservoir rocks consisting of sandstones, siltstones, and shales that were subject to minor alterations, and (3) lower reservoir rocks that were extensively altered. Because of the alteration, intergranular porosity and permeability are reduced with depth. permeability is enhanced by renewable fractures, i.e., fractures that can be reactivated by faulting or natural hydraulic fracturing subsequent to being sealed by mineral deposition. In the central portion of the field, temperature gradients are high near the surface and lower below 700 m. Surface gradients in this elliptically shaped region are fairly constant and define a thermal cap, which does not necessarily correspond to the lithologic cap. At the margin of the field, a narrow transition region, with a low near-surface gradient and an increasing gradient at greater depths, separates the high temperature resource from areas of normal regional gradient. Geophysical and geochemical evidence suggest that vertical convective motion in the reservoir beneath the thermal cap is confined to small units, and small-scale convection is superimposed on large-scale lateral flow of pore fluid. Interpretation of magnetic, resistivity, and gravity anomalies help to establish the relationship between the inferred heat source, the hydrothermal system, and the observed alteration patterns. A simple hydrothermal model is

Gypsy Field project in reservoir characterization

Energy Technology Data Exchange (ETDEWEB)

Castagna, John P.; Jr., O' Meara, Daniel J.

2000-01-12

The overall objective of this project was to use extensive Gypsy Field Laboratory and data as a focus for developing and testing reservoir characterization methods that are targeted at improved recovery of conventional oil. This report describes progress since project report DOE/BC/14970-7 and covers the period June 1997-September 1998 and represents one year of funding originally allocated for the year 1996. During the course of the work previously performed, high resolution geophysical and outcrop data revealed the importance of fractures at the Gypsy site. In addition, personnel changes and alternative funding (OCAST and oil company support of various kinds) allowed the authors to leverage DOE contributions and focus more on geophysical characterization.

Geothermal prospection in the Greater Geneva Basin (Switzerland and France). Impact of diagenesis on reservoir properties of the Upper Jurassic carbonate sediments

Science.gov (United States)

Makhloufi, Yasin; Rusillon, Elme; Brentini, Maud; Clerc, Nicolas; Meyer, Michel; Samankassou, Elias

2017-04-01

Diagenesis of carbonate rocks is known to affect the petrophysical properties (porosity, permeability) of the host rock. Assessing the diagenetic history of the rock is thus essential when evaluating any reservoir exploitation project. The Canton of Geneva (Switzerland) is currently exploring the opportunities for geothermal energy exploitation in the Great Geneva Basin (GGB) sub-surface. In this context, a structural analysis of the basin (Clerc et al., 2016) associated with reservoir appraisal (Brentini et al., 2017) and rock-typing of reservoir bodies of potential interest were conducted (Rusillon et al., 2017). Other geothermal exploitation projects elsewhere (e.g. Bavaria, south Germany, Paris Basin, France) showed that dolomitized carbonate rocks have good reservoir properties and are suitable for geothermal energy production. The objectives of this work are to (1) describe and characterize the dolomitized bodies in the GGB and especially their diagenetic history and (2) quantify the reservoir properties of those bodies (porosity, permeability). Currently, our study focuses on the Upper Jurassic sedimentary bodies of the GGB. Field and well data show that the dolomitization is not ubiquitous in the GGB. Results from the petrographical analyses of the Kimmeridgian cores (Humilly-2) and of field analogues (Jura, Saleve and Vuache mountains) display complex diagenetic histories, dependent of the study sites. The paragenesis exhibits several stages of interparticular calcite cementation as well as different stages of dolomitization and/or dedolomitization. Those processes seem to follow constrained path of fluid migrations through burial, faulting or exhumation during the basin's history. These complex diagenetic histories affected the petrophysical and microstructural properties via porogenesis (conservation of initial porosity, moldic porosity) and/or poronecrosis events. The best reservoir properties appear to be recorded in patch reef and peri

Advances in complex reservoir evaluation based on geophysical well logs

Energy Technology Data Exchange (ETDEWEB)

Fertl, W.H.; Sinha, A.K. (Western Atlas International, Inc., Houston, TX (USA)); McDougall, J.G. (Western Atlas Canada Ltd., Calgary, AB (Canada))

1988-09-01

The matrix of reservoirs having complex lithologies, cause different density, neutron, and acoustic responses. Therefore the lithologies and effective porosity of reservoirs can be determined by using various crossplot techniques on data collected from two of these logs. The Complex Reservoir Analysis program (CRA) computes lithology, porosity, water saturation and relative permeabilities in formations with interbedded limestone, dolomite, and anhydrite. Porosity options include crossplot and individual log response techniques. Corrections for light hydrocarbons were applied. In solving for porosity and mineral volumes, sand, limestone, dolomite, and anhydrite lines were defined on either density/neutron or neutron/acoustic crossplots. Four additional mineral lines were specified. Incorporation of Pe data from the Z-Densilog provided a significant advance in evaluating complex reservoirs via the Z-CRA analysis. The classic reservoir evaluation program CLASS, was used to perform both minerals and shaly evaluation based on density, neutron, resistivity, and natural gamma ray spectral measurements. Computations included total and effective porosities, fluid saturation distribution based on the Wasman-Smits model, productivity indices, and volume and distribution of clay minerals. Additional computed formation parameters included log-derived cation exchange capacity and hydrogen index of dry clay matrix to determine the type and amount of smectite, illite and chlorite/kaolinite present. Canadian field experiences was used to illustrate and support the techniques described. 11 refs., 11 figs., 6 tabs.

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.

Principal permeability determination from multiple horizontal well tests

Energy Technology Data Exchange (ETDEWEB)

Economides, M. [Texas A and M Univ., TX (United States); Munoz, A.; Ehlig-Economides, C.

1998-12-31

A method for obtaining principal permeability magnitudes and direction that requires only the linear flow regime from transient tests in three horizontal wells oriented in three distinct and arbitrary directions, is described. Well design optimization strategies require knowledge of both the principal permeability orientation as well as the horizontal permeability magnitudes. When the degree of horizontal permeability anisotropy (i.e. permeability in the bedding plane with respect to direction) is significant, the productivity of a long horizontal well will depend greatly on its direction, especially when the well is first brought into production. Productivities have been found to deviate substantially among wells in the same reservoir and this deviation has been attributed to differences in well orientation. In view of this fact, measuring permeability anisotropy becomes a compelling necessity. The success of the proposed method is illustrated by a case study in which the principal permeability magnitudes and direction from three wells were used to predict the productivity of a fourth well within 10 per cent. Use of the computed principal permeabilities from the case study, it was possible to forecast the cumulative production to show the significance of well trajectory optimization on the discounted cash flow and the net present value. 20 refs., 3 figs.

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

Coupling a fluid flow simulation with a geomechanical model of a fractured reservoir

OpenAIRE

Segura Segarra, José María; Paz, C.M.; de Bayser, M.; Zhang, J.; Bryant, P.W.; Gonzalez, Nubia Aurora; Rodrigues, E.; Vargas, P.E.; Carol, Ignacio; Lakshmikantha, Ramasesha Mookanahallipatna; Das, K. C.; Sandha, S.S.; Cerqueira, R.; Mello,, U.

2013-01-01

Improving the reliability of integrated reservoir development planning and addressing subsidence, fault reactivation and other environmental impacts, requires increasingly sophisticated geomechanical models, especially in the case of fractured reservoirs where fracture deformation is strongly coupled with its permeability change. Reservoir simulation has historically treated any geomechanical effects by means of a rock compressibility term/table, which can be improved by simulating the actual...

Experimental evaluation on the damages of different drilling modes to tight sandstone reservoirs

Directory of Open Access Journals (Sweden)

Gao Li

2017-07-01

Full Text Available The damages of different drilling modes to reservoirs are different in types and degrees. In this paper, the geologic characteristics and types of such damages were analyzed. Then, based on the relationship between reservoir pressure and bottom hole flowing pressure corresponding to different drilling modes, the experimental procedures on reservoir damages in three drilling modes (e.g. gas drilling, liquid-based underbalanced drilling and overbalanced drilling were designed. Finally, damage simulation experiments were conducted on the tight sandstone reservoir cores of the Jurassic Ahe Fm in the Tarim Basin and Triassic Xujiahe Fm in the central Sichuan Basin. It is shown that the underbalanced drilling is beneficial to reservoir protection because of its less damage on reservoir permeability, but it is, to some extent, sensitive to the stress and the empirical formula of stress sensitivity coefficient is obtained; and that the overbalanced drilling has more reservoir damages due to the invasion of solid and liquid phases. After the water saturation of cores rises to the irreducible water saturation, the decline of gas logging permeability speeds up and the damage degree of water lock increases. It is concluded that the laboratory experiment results of reservoir damage are accordant with the reservoir damage characteristics in actual drilling conditions. Therefore, this method reflects accurately the reservoir damage characteristics and can be used as a new experimental evaluation method on reservoir damage in different drilling modes.

Integration of advanced geoscience and engineering techniques to quantify interwell heterogeneity in reservoir models. Final report, September 29, 1993--September 30, 1996

Energy Technology Data Exchange (ETDEWEB)

Weiss, W.W.; Buckley, J.S.; Ouenes, A.

1997-05-01

The goal of this three-year project was to provide a quantitative definition of reservoir heterogeneity. This objective was accomplished through the integration of geologic, geophysical, and engineering databases into a multi-disciplinary understanding of reservoir architecture and associated fluid-rock and fluid-fluid interactions. This interdisciplinary effort integrated geological and geophysical data with engineering and petrophysical results through reservoir simulation to quantify reservoir architecture and the dynamics of fluid-rock and fluid-fluid interactions. An improved reservoir description allows greater accuracy and confidence during simulation and modeling as steps toward gaining greater recovery efficiency from existing reservoirs. A field laboratory, the Sulimar Queen Unit, was available for the field research. Several members of the PRRC staff participated in the development of improved reservoir description by integration of the field and laboratory data as well as in the development of quantitative reservoir models to aid performance predictions. Subcontractors from Stanford University and the University of Texas at Austin (UT) collaborated in the research and participated in the design and interpretation of field tests. The three-year project was initiated in September 1993 and led to the development and application of various reservoir description methodologies. A new approach for visualizing production data graphically was developed and implemented on the Internet. Using production data and old gamma rays logs, a black oil reservoir model that honors both primary and secondary performance was developed. The old gamma ray logs were used after applying a resealing technique, which was crucial for the success of the project. In addition to the gamma ray logs, the development of the reservoir model benefitted from an inverse Drill Stem Test (DST) technique which provided initial estimates of the reservoir permeability at different wells.

Production performance laws of vertical wells by volume fracturing in CBM reservoirs

Directory of Open Access Journals (Sweden)

Liehui Zhang

2017-05-01

Full Text Available Volume fracturing technology has been widely applied in the development of coalbed methane (CBM reservoirs. As for the stimulated reservoir volume (SRV created by volume fracturing, the seepage laws of fluids are described more accurately and rationally in the rectangular composite model than in the traditional radial composite model. However, the rectangular composite model considering SRV cannot be solved using the analytical or semi-analytical function method, and its solution from the linear flow model has larger errors. In view of this, SRV areas of CBM reservoirs were described by means of dual-medium model in this paper. The complex CBM migration mechanisms were investigated comprehensively, including adsorption, desorption, diffusion and seepage. A well testing model for rectangular composite fracturing wells in CBM reservoirs based on unsteady-state diffusion was built and solved using the boundary element method combined with Laplace transformation, Stehfest numerical inversion and computer programming technology. Thus, production performance laws of CBM reservoirs were clarified. The flow regimes of typical well testing curves were divided and the effects on change laws of production performance from the boundary size of gas reservoirs, permeability of volume fractured areas, adsorption gas content, reservoir permeability and SRV size were analyzed. Eventually, CBM reservoirs after the volume fracturing stimulation were described more accurately and rationally. This study provides a theoretical basis for a better understanding of the CBM migration laws and an approach to evaluating and developing CBM reservoirs efficiently and rationally.

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.

A Systematic Procedure to Describe Shale Gas Permeability Evolution during the Production Process

Science.gov (United States)

Jia, B.; Tsau, J. S.; Barati, R.

2017-12-01

Gas flow behavior in shales is complex due to the multi-physics nature of the process. Pore size reduces as the in-situ stress increases during the production process, which will reduce intrinsic permeability of the porous media. Slip flow/pore diffusion enhances gas apparent permeability, especially under low reservoir pressures. Adsorption not only increases original gas in place but also influences gas flow behavior because of the adsorption layer. Surface diffusion between free gas and adsorption phase enhances gas permeability. Pore size reduction and the adsorption layer both have complex impacts on gas apparent permeability and non-Darcy flow might be a major component in nanopores. Previously published literature is generally incomplete in terms of coupling of all these four physics with fluid flow during gas production. This work proposes a methodology to simultaneously take them into account to describe a permeability evolution process. Our results show that to fully describe shale gas permeability evolution during gas production, three sets of experimental data are needed initially: 1) intrinsic permeability under different in-situ stress, 2) adsorption isotherm under reservoir conditions and 3) surface diffusivity measurement by the pulse-decay method. Geomechanical effects, slip flow/pore diffusion, adsorption layer and surface diffusion all play roles affecting gas permeability. Neglecting any of them might lead to misleading results. The increasing in-situ stress during shale gas production is unfavorable to shale gas flow process. Slip flow/pore diffusion is important for gas permeability under low pressures in the tight porous media. They might overwhelm the geomechanical effect and enhance gas permeability at low pressures. Adsorption layer reduces the gas permeability by reducing the effective pore size, but the effect is limited. Surface diffusion increases gas permeability more under lower pressures. The total gas apparent permeability might

Reservoir Characterization using geostatistical and numerical modeling in GIS with noble gas geochemistry

Science.gov (United States)

Vasquez, D. A.; Swift, J. N.; Tan, S.; Darrah, T. H.

2013-12-01

The integration of precise geochemical analyses with quantitative engineering modeling into an interactive GIS system allows for a sophisticated and efficient method of reservoir engineering and characterization. Geographic Information Systems (GIS) is utilized as an advanced technique for oil field reservoir analysis by combining field engineering and geological/geochemical spatial datasets with the available systematic modeling and mapping methods to integrate the information into a spatially correlated first-hand approach in defining surface and subsurface characteristics. Three key methods of analysis include: 1) Geostatistical modeling to create a static and volumetric 3-dimensional representation of the geological body, 2) Numerical modeling to develop a dynamic and interactive 2-dimensional model of fluid flow across the reservoir and 3) Noble gas geochemistry to further define the physical conditions, components and history of the geologic system. Results thus far include using engineering algorithms for interpolating electrical well log properties across the field (spontaneous potential, resistivity) yielding a highly accurate and high-resolution 3D model of rock properties. Results so far also include using numerical finite difference methods (crank-nicholson) to solve for equations describing the distribution of pressure across field yielding a 2D simulation model of fluid flow across reservoir. Ongoing noble gas geochemistry results will also include determination of the source, thermal maturity and the extent/style of fluid migration (connectivity, continuity and directionality). Future work will include developing an inverse engineering algorithm to model for permeability, porosity and water saturation.This combination of new and efficient technological and analytical capabilities is geared to provide a better understanding of the field geology and hydrocarbon dynamics system with applications to determine the presence of hydrocarbon pay zones (or

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.

Reservoir characteristics and control factors of Carboniferous volcanic gas reservoirs in the Dixi area of Junggar Basin, China

Directory of Open Access Journals (Sweden)

Ji'an Shi

2017-02-01

Full Text Available Field outcrop observation, drilling core description, thin-section analysis, SEM analysis, and geochemistry, indicate that Dixi area of Carboniferous volcanic rock gas reservoir belongs to the volcanic rock oil reservoir of the authigenic gas reservoir. The source rocks make contact with volcanic rock reservoir directly or by fault, and having the characteristics of near source accumulation. The volcanic rock reservoir rocks mainly consist of acidic rhyolite and dacite, intermediate andesite, basic basalt and volcanic breccia: (1 Acidic rhyolite and dacite reservoirs are developed in the middle-lower part of the structure, have suffered strong denudation effect, and the secondary pores have formed in the weathering and tectonic burial stages, but primary pores are not developed within the early diagenesis stage. Average porosity is only at 8%, and the maximum porosity is at 13.5%, with oil and gas accumulation showing poor performance. (2 Intermediate andesite and basic basalt reservoirs are mainly distributed near the crater, which resembles the size of and suggests a volcanic eruption. Primary pores are formed in the early diagenetic stage, secondary pores developed in weathering and erosion transformation stage, and secondary fractures formed in the tectonic burial stage. The average porosity is at 9.2%, and the maximum porosity is at 21.9%: it is of the high-quality reservoir types in Dixi area. (3 The volcanic breccia reservoir has the same diagenetic features with sedimentary rocks, but also has the same mineral composition with volcanic rock; rigid components can keep the primary porosity without being affected by compaction during the burial process. At the same time, the brittleness of volcanic breccia reservoir makes it easily fracture under the stress; internal fracture was developmental. Volcanic breccia developed in the structural high part and suffered a long-term leaching effect. The original pore-fracture combination also made

Seismic signatures of the Lodgepole fractured reservoir in Utah-Wyoming overthrust belt

Energy Technology Data Exchange (ETDEWEB)

Parra, J.; Collier, H.; Angstman, B.

1997-08-01

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. An important approach to characterizing the fracture orientation and fracture permeability of reservoir formations is one based upon the effects of such conditions on the propagation of acoustic and seismic waves in the rock. We present the feasibility of using seismic measurement techniques to map the fracture zones between wells spaced 2400 ft at depths of about 1000 ft. For this purpose we constructed computer models (which include azimuthal anisotropy) using Lodgepole reservoir parameters to predict seismic signatures recorded at the borehole scale, crosswell scale, and 3 D seismic scale. We have integrated well logs with existing 2D surfaces seismic to produce petrophysical and geological cross sections to determine the reservoir parameters and geometry for the computer models. In particular, the model responses are used to evaluate if surface seismic and crosswell seismic measurements can capture the anisotropy due to vertical fractures. Preliminary results suggested that seismic waves transmitted between two wells will propagate in carbonate fracture reservoirs, and the signal can be received above the noise level at the distance of 2400 ft. In addition, the large velocities contrast between the main fracture zone and the underlying unfractured Boundary Ridge Member, suggested that borehole reflection imaging may be appropriate to map and fracture zone thickness variation and fracture distributions in the reservoir.

Naturally fractured tight gas reservoir detection optimization

Energy Technology Data Exchange (ETDEWEB)

NONE

1999-06-01

Building upon the partitioning of the Greater Green River Basin (GGRB) that was conducted last quarter, the goal of the work this quarter has been to conclude evaluation of the Stratos well and the prototypical Green River Deep partition, and perform the fill resource evaluation of the Upper Cretaceous tight gas play, with the goal of defining target areas of enhanced natural fracturing. The work plan for the quarter of November 1-December 31, 1998 comprised four tasks: (1) Evaluation of the Green River Deep partition and the Stratos well and examination of potential opportunity for expanding the use of E and P technology to low permeability, naturally fractured gas reservoirs, (2) Gas field studies, and (3) Resource analysis of the balance of the partitions.

Improving reservoir conformance using gelled polymer systems. Annual report, September 25, 1994--September 24, 1995

Energy Technology Data Exchange (ETDEWEB)

Green, D.W.; Willhite, G.P.

1996-05-01

The objectives of the research program are to (1) identify and develop polymer systems which have potential to improve reservoir conformance of fluid displacement processes, (2) determine the performance of these systems in bulk and in porous media, and (3) develop methods to predict their performance in field applications. The research focused on four types of gel systems -- KUSP1 systems which contain an aqueous polysaccharide designated KUSP1, phenolic-aldehyde systems composed of resorcinol and formaldehyde, colloidal-dispersion systems composed of polyacrylamide and aluminum citrate, and a chromium-based system where polyacrylamide is crosslinked by chromium(III). Gelation behavior of the resorcinol-formaldehyde systems and the KUSP1-borate system was examined. Size distributions of aggregates that form in the polyacrylamide-aluminum colloidal-dispersion gel system were determined. Permeabilities to brine of several rock materials were significantly reduced by gel treatments using the KUSP1 polymer-ester (monoethylphthalate) system, the KUSP1 polymer-boric acid system, and the sulfomethylated resorcinol-formaldehyde system. The KUSP1 polymer-ester system and the sulfomethylated resorcinol-formaldehyde system were also shown to significantly reduce the permeability to super-critical carbon dioxide. A mathematical model was developed to simulate the behavior of a chromium redox-polyacrylamide gel system that is injected through a wellbore into a multi-layer reservoir in which crossflow between layers is allowed. The model describes gelation kinetics and filtration of pre-gel aggregates in the reservoir. Studies using the model demonstrated the effect filtration of gel aggregates has on the placement of gel systems in layered reservoirs.

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.

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

Numerical modeling of shear stimulation in naturally fractured geothermal reservoirs

OpenAIRE

Ucar, Eren

2018-01-01

Shear-dilation-based hydraulic stimulations are conducted to create enhanced geothermal systems (EGS) from low permeable geothermal reservoirs, which are initially not amenable to energy production. Reservoir stimulations are done by injecting low-pressurized fluid into the naturally fractured formations. The injection aims to activate critically stressed fractures by decreasing frictional strength and ultimately cause a shear failure. The shear failure leads to a permanent ...

Suitability of Torrent Permeability Tester to measure air-permeability of covercrete

Energy Technology Data Exchange (ETDEWEB)

Andrade, C.; Gonzales-Gasca, C. [Institute of Construction Sciences ' Eduardo Torroja' , Madrid (Spain); Torrent, R. [Portland Cement Institute, (Argentina)

2000-07-01

Suitability of the Torrent Permeability Tester (TPT) to measure the permeability of covercrete to air, both in the laboratory and the field, is investigated, and test results obtained in laboratory studies are discussed. The tests performed included the determination of air permeability (TPT method), oxygen permeability (Cembureau method) and capillary suction, rapid chloride permeability test (ASTM C 1202), as well as a one-year carbonation depth test. Concrete specimens of various compositions and curing regimes were used in the tests; the gas-permeability tests were repeated on the same specimens after 28 days, than again at 6 months and 12 months. Test results confirmed the suitability of the TPT as a useful tool in the characterization of the quality the of concrete cover. It was found to be sensitive to changes in concrete quality; repeatable for sensitive properties such as gas permeability ; also, it was found to correlate well with other durability-related properties. 10 refs., 8 tabs., 8 figs.

Approaches to identifying reservoir heterogeneity and reserve growth opportunities from subsurface data: The Oficina Formation, Budare field, Venezuela

Energy Technology Data Exchange (ETDEWEB)

Hamilton, D.S.; Raeuchle, S.K.; Holtz, M.H. [Bureau of Economic Geology, Austin, TX (United States)] [and others

1997-08-01

We applied an integrated geologic, geophysical, and engineering approach devised to identify heterogeneities in the subsurface that might lead to reserve growth opportunities in our analysis of the Oficina Formation at Budare field, Venezuela. The approach involves 4 key steps: (1) Determine geologic reservoir architecture; (2) Investigate trends in reservoir fluid flow; (3) Integrate fluid flow trends with reservoir architecture; and (4) Estimate original oil-in-place, residual oil saturation, and remaining mobile oil, to identify opportunities for reserve growth. There are three main oil-producing reservoirs in the Oficina Formation that were deposited in a bed-load fluvial system, an incised valley-fill, and a barrier-strandplain system. Reservoir continuity is complex because, in addition to lateral facies variability, the major Oficina depositional systems were internally subdivided by high-frequency stratigraphic surfaces. These surfaces define times of intermittent lacustrine and marine flooding events that punctuated the fluvial and marginal marine sedimentation, respectively. Syn and post depositional faulting further disrupted reservoir continuity. Trends in fluid flow established from initial fluid levels, response to recompletion workovers, and pressure depletion data demonstrated barriers to lateral and vertical fluid flow caused by a combination of reservoir facies pinchout, flooding shale markers, and the faults. Considerable reserve growth potential exists at Budare field because the reservoir units are highly compartment by the depositional heterogeneity and structural complexity. Numerous reserve growth opportunities were identified in attics updip of existing production, in untapped or incompletely drained compartments, and in field extensions.

Advanced productivity forecast using petrophysical wireline data calibrated with MDT tests and numerical reservoir simulation

Energy Technology Data Exchange (ETDEWEB)

Andre, Carlos de [PETROBRAS, Rio de Janeiro, RJ (Brazil); Canas, Jesus A.; Low, Steven; Barreto, Wesley [Schlumberger, Houston, TX (United States)

2004-07-01

This paper describes an integrated and rigorous approach for viscous and middle oil reservoir productivity evaluation using petrophysical models calibrated with permeability derived from mini tests (Dual Packer) and Vertical Interference Tests (VIT) from open hole wire line testers (MDT SLB TM). It describes the process from Dual Packer Test and VIT pre-job design, evaluation via analytical and inverse simulation modeling, calibration and up scaling of petrophysical data into a numerical model, history matching of Dual Packer Tests and VIT with numerical simulation modeling. Finally, after developing a dynamic calibrated model, we perform productivity forecasts of different well configurations (vertical, horizontal and multilateral wells) for several deep offshore oil reservoirs in order to support well testing activities and future development strategies. The objective was to characterize formation static and dynamic properties early in the field development process to optimize well testing design, extended well test (EWT) and support the development strategies in deep offshore viscous oil reservoirs. This type of oil has limitations to flow naturally to surface and special lifting equipment is required for smooth optimum well testing/production. The integrated analysis gave a good overall picture of the formation, including permeability anisotropy and fluid dynamics. Subsequent analysis of different well configurations and lifting schemes allows maximizing formation productivity. The simulation and calibration results are compared to measured well test data. Results from this work shows that if the various petrophysical and fluid properties sources are integrated properly an accurate well productivity model can be achieved. If done early in the field development program, this time/knowledge gain could reduce the risk and maximize the development profitability of new blocks (value of the information). (author)

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

Field investigation with regard to the impermeability of clay formations. Helium-4 soil gas surveys in sedimentary basins as a tentative study of secondary permeability in clayey sequences

International Nuclear Information System (INIS)

Lombardi, S.; Benvegnu, F.; Brondi, A.; Polizzano, C.

1993-01-01

This report deals with a tentative study for the detection of the secondary permeability in clayey formations conducted in several sedimentary basins in Central Italy, by means of geochemical methods. The main purposes are: to try a geochemical method, based on the distribution of deep origin gases in soil gas ( 4 He and 222 Rn), to detect buried fault systems and to study the permeability of clay as a potential migration pathway for nuclides of radioactive waste deposits; to verify the effectiveness of this method for the selection of suitable sites for radwaste disposal. This research programme consists in a collaboration between ENEA and the University of Rome within the communitarian programme for the disposal of high level and long-live radwaste. Investigations concerned sedimentary basins filled by sand-clay formations 1000-2000 meters thick and characterized by different tectonic: Era and Chiani-Paglia Valleys (Tuscany and North Latium), structural trenches due to extensive tectonics along the tyrrhenian edge, and Vasto region, a basin in the 'Adriatic foretrench', characterized by compressive tectonics. The investigated areas are near or directly correspond to geothermal fields or to hydrocarbon reservoirs supplying gases which may migrate upward along fractures. Almost 4000 soil gas samples were collected in the three surveyed areas; the sampling density was of about 1.5 points / km 2 , normally used in the regional scale surveys. The obtained results show that the observed helium anomalies are distributed or elongated according to the main tectonic features of the substratum (fault systems, fractures, deep structures); the magnitude of anomalies seems to correlate with the nature of the deep gas reservoir (i.e. oil in Vasto), geothermal reservoir in the Paglia valley. These observations seem to confirm that the presence of deep origin gases in soils is controlled by tectonics. Clay thickness does not significantly control the uprising of deep gases: in

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

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.

Formation evaluation in liquid-dominated geothermal reservoirs

Energy Technology Data Exchange (ETDEWEB)

Ershaghi, I.; Dougherty, E.E.; Handy, L.L.

1981-04-01

Studies relative to some formation evaluation aspects of geothermal reservoirs are reported. The particular reservoirs considered were the liquid dominated type with a lithology of the sedimentary nature. Specific problems of interest included the resistivity behavior of brines and rocks at elevated temperatures and studies on the feasibility of using the well log resistivity data to obtain estimates of reservoir permeability. Several papers summarizing the results of these studies were presented at various technical meetings for rapid dissemination of the results to potential users. These papers together with a summary of data most recently generated are included. A brief review of the research findings precedes the technical papers. Separate abstracts were prepared for four papers. Five papers were abstracted previously for EDB.

Behaviour of gas production from type 3 hydrate reservoirs

Energy Technology Data Exchange (ETDEWEB)

Pooladi-Darvish, M. [Calgary Univ., AB (Canada). Dept. of Chemical and Petroleum Engineering]|[Fekete Associates Inc., Calgary, AB (Canada); Zatsepina, O. [Calgary Univ., AB (Canada). Dept. of Chemical and Petroleum Engineering; Hong, H. [Fekete Associates Inc., Calgary, AB (Canada)

2008-07-01

The possible role of gas hydrates as a potential energy resource was discussed with particular reference to methods for estimating the rate of gas production from hydrate reservoirs under different operating conditions. This paper presented several numerical simulations studies of gas production from type 3 hydrate reservoirs in 1-D and 2-D geometries. Type 3 reservoirs include gas production from hydrate-reservoirs that lie totally within the hydrate stability zone and are sandwiched by impermeable layers on top and bottom. The purpose of this study was to better understand hydrate decomposition by depressurization. The study questioned whether 1-D modeling of type 3 hydrate reservoirs is a reasonable approximation. It also determined whether gas rate increases or decreases with time. The important reservoir characteristics for determining the rate of gas production were identified. Last, the study determined how competition between fluid and heat flow affects hydrate decomposition. This paper also described the relation and interaction between the heat and fluid flow mechanisms in depressurization of type 3 hydrate reservoirs. All results of 1-D and 2-D numerical simulation and analyses were generated using the STARS simulator. It was shown that the rate of gas production depends on the initial pressure/temperature conditions and permeability of the hydrate bearing formation. A high peak rate may be achieved under favourable conditions, but this peak rate is obtained after an initial period where the rate of gas production increases with time. The heat transfer in the direction perpendicular to the direction of fluid flow is significant, requiring 2D modeling. The hydraulic diffusivity is low because of the low permeability of hydrate-bearing formations. This could result in competition between heat and fluid flow, thereby influencing the behaviour of decomposition. 6 refs., 3 tabs., 12 figs.

Development of a segmentation method for analysis of Campos basin typical reservoir rocks

Energy Technology Data Exchange (ETDEWEB)

Rego, Eneida Arendt; Bueno, Andre Duarte [Universidade Estadual do Norte Fluminense Darcy Ribeiro (UENF), Macae, RJ (Brazil). Lab. de Engenharia e Exploracao de Petroleo (LENEP)]. E-mails: eneida@lenep.uenf.br; bueno@lenep.uenf.br

2008-07-01

This paper represents a master thesis proposal in Exploration and Reservoir Engineering that have the objective to development a specific segmentation method for digital images of reservoir rocks, which produce better results than the global methods available in the bibliography for the determination of rocks physical properties as porosity and permeability. (author)

Correcting underestimation of optimal fracture length by modeling proppant conductivity variations in hydraulically fractured gas/condensate reservoirs

Energy Technology Data Exchange (ETDEWEB)

Akram, A.H.; Samad, A. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Schlumberger, Houston, TX (United States)

2006-07-01

A study was conducted in which a newly developed numerical simulator was used to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir. The effect of condensate dropout was modeled in both the reservoir and the proppant pack. The type of proppant and the stress applied to it are among the factors that determine proppant conductivity in a single-phase flow. Other factors include the high velocity of gas and the presence of liquid in the proppant pack. It was concluded that apparent proppant permeability in a gas condensate reservoir varies along the length of the hydraulic fracture and depends on the distance from the wellbore. It will increase towards the tip of the fracture where liquid ratio and velocity are lower. Apparent proppant permeability also changes with time. Forecasting is most accurate when these conditions are considered in the simulation. There are 2 problems associated with the use of a constant proppant permeability in a gas condensate reservoir. The first relates to the fact that it is impossible to obtain a correct single number that will mimic the drawdown of the real fracture at a particular rate without going through the process of determining the proppant permeability profile in a numerical simulator. The second problem relates to the fact that constant proppant permeability yields an optimal fracture length that is too short. Analytical modeling does not account for these complexities. It was determined that the only way to accurately simulate the behaviour of a hydraulic fracture in a high rate well, is by advanced numerical modeling that considers varying apparent proppant permeability in terms of time and distance along the fracture length. 10 refs., 2 tabs., 16 figs., 1 appendix.

Incorporating Scale-Dependent Fracture Stiffness for Improved Reservoir Performance Prediction

Science.gov (United States)

Crawford, B. R.; Tsenn, M. C.; Homburg, J. M.; Stehle, R. C.; Freysteinson, J. A.; Reese, W. C.

2017-12-01

We present a novel technique for predicting dynamic fracture network response to production-driven changes in effective stress, with the potential for optimizing depletion planning and improving recovery prediction in stress-sensitive naturally fractured reservoirs. A key component of the method involves laboratory geomechanics testing of single fractures in order to develop a unique scaling relationship between fracture normal stiffness and initial mechanical aperture. Details of the workflow are as follows: tensile, opening mode fractures are created in a variety of low matrix permeability rocks with initial, unstressed apertures in the micrometer to millimeter range, as determined from image analyses of X-ray CT scans; subsequent hydrostatic compression of these fractured samples with synchronous radial strain and flow measurement indicates that both mechanical and hydraulic aperture reduction varies linearly with the natural logarithm of effective normal stress; these stress-sensitive single-fracture laboratory observations are then upscaled to networks with fracture populations displaying frequency-length and length-aperture scaling laws commonly exhibited by natural fracture arrays; functional relationships between reservoir pressure reduction and fracture network porosity, compressibility and directional permeabilities as generated by such discrete fracture network modeling are then exported to the reservoir simulator for improved naturally fractured reservoir performance prediction.

INTEGRATED GEOLOGIC-ENGINEERING MODEL FOR REEF AND CARBONATE SHOAL RESERVOIRS ASSOCIATED WITH PALEOHIGHS: UPPER JURASSIC SMACKOVER FORMATION, NORTHEASTERN GULF OF MEXICO

Energy Technology Data Exchange (ETDEWEB)

Ernest A. Mancini

2002-09-25

heterogeneity in these reef and shoal reservoirs have been made. Petrophysical and engineering property characterization has been essentially completed. Porosity and permeability data at Appleton and Vocation Fields have been analyzed, and well performance analysis has been conducted. Data integration is up to date, in that, the geological, geophysical, petrophysical and engineering data collected to date for Appleton and Vocation Fields have been compiled into a fieldwide digital database. 3-D geologic modeling of the structures and reservoirs at Appleton and Vocation Fields has been completed. The model represents an integration of geological, petrophysical and seismic data. 3-D reservoir simulation of the reservoirs at Appleton and Vocation Fields has been completed. The 3-D geologic model served as the framework for the simulations. A technology workshop on reservoir characterization and modeling at Appleton and Vocation Fields was conducted to transfer the results of the project to the petroleum industry.

Interpretation of Water Tracer Simulation in the H-1 Segment of the Gullfaks Field

Energy Technology Data Exchange (ETDEWEB)

Moid, Farrukh

2000-07-01

This thesis describes the water tracer simulation in the H-1 segment of the Gullfaks field. Three passive water tracer slugs were injected from the two producing wells during water flooding, pressure maintenance and reservoir monitoring program in the Gullfaks field. The same program is considered in this thesis. Computer Modelling Group's (CMG) simulator STARS is used for the general reservoir simulation and a separate module for tracer flow (ITRC-SIM) which is incorporated in the STARS and developed at Institute For Energy (IFE) is used for the tracer simulation. Water cut and tracer concentration data are used in history matching of the field. History matching is performed by changing the transmissibility and permeability of different layers; also the effect of changing saturations near the well bore on history matching is examined. It is noted that water cut is sensitive to transmissibility of the layers and the saturation around the well bore. Tracers are found to be moving in the most permeable layers. The corresponding history matching of water and tracer production shows a severe loss of first tracer injected because of imbibition process. Water phase velocity and areal communication between different wells are determined. Advance numerical features of tracer module ITRC-SIM such as flux limiting scheme and grid refinement scheme are evaluated and are found to be an important tool for reducing the numerical smearing. The effects of dispersion and diffusion on tracer response curve are also evaluated. Dispersion makes the tracer concentration curve smeared. Simulation results of water cut and tracer concentration show a good history match for this reservoir. The improved simulation model and the tracer module for this reservoir can be used for the prediction of future performance of the reservoir and interpretation of the tracer behaviour in the reservoir. (author)

DELIVERABLE 2.1.1 POROSITY/PERMEABILITY CROSS-PLOTS: CHEROKEE AND BUG FIELDS, SAN JUAN COUNTY, UTAH, AND LITTLE UTE AND SLEEPING UTE FIELDS, MONTEZUMA COUNTY, COLORADO

International Nuclear Information System (INIS)

Chidsey, Thomas C. Jr.; Eby, David E.; Wray, Laura L.

2003-01-01

Over 400 million barrels (64 million m 3 ) of oil have been produced from the shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation in the Paradox Basin, Utah and Colorado. With the exception of the giant Greater Aneth field, the other 100 plus oil fields in the basin typically contain 2 to 10 million barrels (0.3-1.6 million m 3 ) of original oil in place. Most of these fields are characterized by high initial production rates followed by a very short productive life (primary), and hence premature abandonment. Only 15 to 25 percent of the original oil in place is recoverable during primary production from conventional vertical wells. An extensive and successful horizontal drilling program has been conducted in the giant Greater Aneth field. However, to date, only two horizontal wells have been drilled in small Ismay and Desert Creek fields. The results from these wells were disappointing due to poor understanding of the carbonate facies and diagenetic fabrics that create reservoir heterogeneity. These small fields, and similar fields in the basin, are at high risk of premature abandonment. At least 200 million barrels (31.8 million m 3 ) of oil will be left behind in these small fields because current development practices leave compartments of the heterogeneous reservoirs undrained. Through proper geological evaluation of the reservoirs, production may be increased by 20 to 50 percent through the drilling of low-cost single or multilateral horizontal legs from existing vertical development wells. In addition, horizontal drilling from existing wells minimizes surface disturbances and costs for field development, particularly in the environmentally sensitive areas of southeastern Utah and southwestern Colorado

Characterizing hydraulic fractures in shale gas reservoirs using transient pressure tests

Directory of Open Access Journals (Sweden)

Cong Wang

2015-06-01

This work presents an unconventional gas reservoir simulator and its application to quantify hydraulic fractures in shale gas reservoirs using transient pressure data. The numerical model incorporates most known physical processes for gas production from unconventional reservoirs, including two-phase flow of liquid and gas, Klinkenberg effect, non-Darcy flow, and nonlinear adsorption. In addition, the model is able to handle various types and scales of fractures or heterogeneity using continuum, discrete or hybrid modeling approaches under different well production conditions of varying rate or pressure. Our modeling studies indicate that the most sensitive parameter of hydraulic fractures to early transient gas flow through extremely low permeability rock is actually the fracture-matrix contacting area, generated by fracturing stimulation. Based on this observation, it is possible to use transient pressure testing data to estimate the area of fractures generated from fracturing operations. We will conduct a series of modeling studies and present a methodology using typical transient pressure responses, simulated by the numerical model, to estimate fracture areas created or to quantity hydraulic fractures with traditional well testing technology. The type curves of pressure transients from this study can be used to quantify hydraulic fractures in field application.

Measuring the permeability of Eleana argillite from area 17, Nevada Test Site, using the transient method

International Nuclear Information System (INIS)

Lin, W.

1978-01-01

Using the transient method, we determine the permeability of high-quartz Eleana argillite from the Nevada Test Site as a function of effective pressure. By comparing calculated and observed pressure decay in the upstream reservoir, we have determined the permeability of intact and fractured specimens at effective pressures ranging from 1.0 to 24.0 MPa. Over this pressure range, Eleana argillite has a low permeability (10 -16 to 10 -19 cm 2 ) when intact and a higher permeability (10 -12 to 10 -17 cm 2 ) with one induced through-going fracture

Reservoir Performance Under Future Climate For Basins With Different Hydrologic Sensitivities

Science.gov (United States)

Mateus, M. C.; Tullos, D. D.

2013-12-01

In addition to long-standing uncertainties related to variable inflows and market price of power, reservoir operators face a number of new uncertainties related to hydrologic nonstationarity, changing environmental regulations, and rapidly growing water and energy demands. This study investigates the impact, sensitivity, and uncertainty of changing hydrology on hydrosystem performance across different hydrogeologic settings. We evaluate the performance of reservoirs in the Santiam River basin, including a case study in the North Santiam Basin, with high permeability and extensive groundwater storage, and the South Santiam Basin, with low permeability, little groundwater storage and rapid runoff response. The modeling objective is to address the following study questions: (1) for the two hydrologic regimes, how does the flood management, water supply, and environmental performance of current reservoir operations change under future 2.5, 50 and 97.5 percentile streamflow projections; and (2) how much change in inflow is required to initiate a failure to meet downstream minimum or maximum flows in the future. We couple global climate model results with a rainfall-runoff model and a formal Bayesian uncertainty analysis to simulate future inflow hydrographs as inputs to a reservoir operations model. To evaluate reservoir performance under a changing climate, we calculate reservoir refill reliability, changes in flood frequency, and reservoir time and volumetric reliability of meeting minimum spring and summer flow target. Reservoir performance under future hydrology appears to vary with hydrogeology. We find higher sensitivity to floods for the North Santiam Basin and higher sensitivity to minimum flow targets for the South Santiam Basin. Higher uncertainty is related with basins with a more complex hydrologeology. Results from model simulations contribute to understanding of the reliability and vulnerability of reservoirs to a changing climate.

History matching and parameter estimation of surface deformation data for a CO2 sequestration field project using ensemble-based algorithm

Science.gov (United States)

Ping, J.; Tavakoli, R.; Min, B.; Srinivasan, S.; Wheeler, M. F.

2015-12-01

Optimal management of subsurface processes requires the characterization of the uncertainty in reservoir description and reservoir performance prediction. The application of ensemble-based algorithms for history matching reservoir models has been steadily increasing over the past decade. However, the majority of implementations in the reservoir engineering have dealt only with production history matching. During geologic sequestration, the injection of large quantities of CO2 into the subsurface may alter the stress/strain field which in turn can lead to surface uplift or subsidence. Therefore, it is essential to couple multiphase flow and geomechanical response in order to predict and quantify the uncertainty of CO2 plume movement for long-term, large-scale CO2 sequestration projects. In this work, we simulate and estimate the properties of a reservoir that is being used to store CO2 as part of the In Salah Capture and Storage project in Algeria. The CO2 is separated from produced natural gas and is re-injected into downdip aquifer portion of the field from three long horizontal wells. The field observation data includes ground surface deformations (uplift) measured using satellite-based radar (InSAR), injection well locations and CO2 injection rate histories provided by the operators. We implement ensemble-based algorithms for assimilating both injection rate data as well as geomechanical observations (surface uplift) into reservoir model. The preliminary estimation results of horizontal permeability and material properties such as Young Modulus and Poisson Ratio are consistent with available measurements and previous studies in this field. Moreover, the existence of high-permeability channels/fractures within the reservoir; especially in the regions around the injection wells are confirmed. This estimation results can be used to accurately and efficiently predict and monitor the movement of CO2 plume.

Adaptive forward-inverse modeling of reservoir fluids away from wellbores; TOPICAL

International Nuclear Information System (INIS)

Ziagos, J P; Gelinas, R J; Doss, S K; Nelson, R G

1999-01-01

This Final Report contains the deliverables of the DeepLook Phase I project entitled, ''Adaptive Forward-Inverse Modeling of Reservoir Fluids Away from Wellbores''. The deliverables are: (i) a description of 2-D test problem results, analyses, and technical descriptions of the techniques used, (ii) a listing of program setup commands that construct and execute the codes for selected test problems (these commands are in mathematical terminology, which reinforces technical descriptions in the text), and (iii) an evaluation and recommendation regarding continuance of this project, including considerations of possible extensions to 3-D codes, additional technical scope, and budget for the out-years. The far-market objective in this project is to develop advanced technologies that can help locate and enhance the recovery of oil from heterogeneous rock formations. The specific technical objective in Phase I was to develop proof-of-concept of new forward and inverse (F-I) modeling techniques[Gelinas et al, 1998] that seek to enhance estimates (images) of formation permeability distributions and fluid motion away from wellbore volumes. This goes to the heart of improving industry's ability to jointly image reservoir permeability and flow predictions of trapped and recovered oil versus time. The estimation of formation permeability away from borehole measurements is an ''inverse'' problem. It is an inseparable part of modeling fluid flows throughout the reservoir in efforts to increase the efficiency of oil recovery at minimum cost. Classic issues of non-uniqueness, mathematical instability, noise effects, and inadequate numerical solution techniques have historically impeded progress in reservoir parameter estimations. Because information pertaining to fluid and rock properties is always sampled sparsely by wellbore measurements, a successful method for interpolating permeability and fluid data between the measurements must be: (i) physics-based, (ii) conditioned by signal

Magnetic field extraction of trap-based electron beams using a high-permeability grid

International Nuclear Information System (INIS)

Hurst, N. C.; Danielson, J. R.; Surko, C. M.

2015-01-01

A method to form high quality electrostatically guided lepton beams is explored. Test electron beams are extracted from tailored plasmas confined in a Penning-Malmberg trap. The particles are then extracted from the confining axial magnetic field by passing them through a high magnetic permeability grid with radial tines (a so-called “magnetic spider”). An Einzel lens is used to focus and analyze the beam properties. Numerical simulations are used to model non-adiabatic effects due to the spider, and the predictions are compared with the experimental results. Improvements in beam quality are discussed relative to the use of a hole in a high permeability shield (i.e., in lieu of the spider), and areas for further improvement are described

Fortescue reservoir development and reservoir studies

Energy Technology Data Exchange (ETDEWEB)

Henzell, S.T.; Hicks, G.J.; Horden, M.J.; Irrgang, H.R.; Janssen, E.J.; Kable, C.W.; Mitchell, R.A.H.; Morrell, N.W.; Palmer, I.D.; Seage, N.W.

1985-03-01

The Fortescue field in the Gippsland Basin, offshore southeastern Australia is being developed from two platforms (Fortescue A and Cobia A) by Esso Australia Ltd. (operator) and BHP Petroleum. The Fortescue reservoir is a stratigraphic trap at the top of the Latrobe Group of sediments. It overlies the western flank of the Halibut and Cobia fields and is separated from them by a non-net sequence of shales and coals which form a hydraulic barrier between the two systems. Development drilling into the Fortescue reservoir commenced in April 1983 with production coming onstream in May 1983. Fortescue, with booked reserves of 44 stock tank gigalitres (280 million stock tank barrels) of 43/sup 0/ API oil, is the seventh major oil reservoir to be developed in the offshore Gippsland Basin by Esso/BHP. In mid-1984, after drilling a total of 20 exploration and development wells, and after approximately one year of production, a detailed three-dimensional, two-phase reservoir simulation study was performed to examine the recovery efficiency, drainage patterns, pressure performance and production rate potential of the reservoir. The model was validated by history matching an extensive suite of Repeat Formation Test (RFT) pressure data. The results confirmed the reserves basis, and demonstrated that the ultimate oil recovery from the reservoir is not sensitive to production rate. This result is consistent with studies on other high quality Latrobe Group reservoirs in the Gippsland Basin which contain undersaturated crudes and receive very strong water drive from the Basin-wide aquifer system. With the development of the simulation model during the development phase, it has been possible to more accurately define the optimal well pattern for the remainder of the development.

Reservoir characterization of the Upper Jurassic geothermal target formations (Molasse Basin, Germany): role of thermofacies as exploration tool

Science.gov (United States)

Homuth, S.; Götz, A. E.; Sass, I.

2015-06-01

The Upper Jurassic carbonates of the southern German Molasse Basin are the target of numerous geothermal combined heat and power production projects since the year 2000. A production-orientated reservoir characterization is therefore of high economic interest. Outcrop analogue studies enable reservoir property prediction by determination and correlation of lithofacies-related thermo- and petrophysical parameters. A thermofacies classification of the carbonate formations serves to identify heterogeneities and production zones. The hydraulic conductivity is mainly controlled by tectonic structures and karstification, whilst the type and grade of karstification is facies related. The rock permeability has only a minor effect on the reservoir's sustainability. Physical parameters determined on oven-dried samples have to be corrected, applying reservoir transfer models to water-saturated reservoir conditions. To validate these calculated parameters, a Thermo-Triaxial-Cell simulating the temperature and pressure conditions of the reservoir is used and calorimetric and thermal conductivity measurements under elevated temperature conditions are performed. Additionally, core and cutting material from a 1600 m deep research drilling and a 4850 m (total vertical depth, measured depth: 6020 m) deep well is used to validate the reservoir property predictions. Under reservoir conditions a decrease in permeability of 2-3 magnitudes is observed due to the thermal expansion of the rock matrix. For tight carbonates the matrix permeability is temperature-controlled; the thermophysical matrix parameters are density-controlled. Density increases typically with depth and especially with higher dolomite content. Therefore, thermal conductivity increases; however the dominant factor temperature also decreases the thermal conductivity. Specific heat capacity typically increases with increasing depth and temperature. The lithofacies-related characterization and prediction of reservoir

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

Oxygen isotope studies of the Salton Sea geothermal field

International Nuclear Information System (INIS)

Olson, E.R.

1978-01-01

Interbedded shales and sandstones were drilled to a depth of 1588 metres in Sinclair Number Four Well, Salton Sea Geothermal Field. Bottom hole temperatures are approximately 290 0 C. The oxygen dels of hydrothermal and detrital calcite have a systematic relationship at any depth in the geothermal reservoir. Typical values are: vein calcite, +6 0 / 00 ; calcite in white sandstone, +10 0 / 00 ; calcite in dark gray shale, +11 0 / 00 ; calcite in light gray shale, +17 0 / 00 ; calcite in red-brown shale, +20 0 / 00 . This succession represents decreasing water-rock interaction that is also indicated by the clay mineralogy of the shales. Permeability has a marked effect on the equilibration of water and rocks at any given temperature. Original differences in permeability have resulted in partial preservation of original detrital sedimentary compositions. The fluids in the Salton Sea Geothermal Field are probabaly partially evaporated Colorado River water, and their oxygen del values vary as much as 4 0 / 00 throughout the field. Truesdell's (1974) data suggest that dissolved salts may make the water oxygen activity del as much as 6 0 / 00 greater than the concentration del in the geothermal reservoir. Such an uncertainty is a serious impediment to precise isotope geothermometry in this system.(auth.)

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

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.

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.

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.)

Geostatistical modeling of a fluviodeltaic reservoir in the Huyapari Field, Hamaca area, in the Faja Petrolifera del Orinoco, Venezuela

Energy Technology Data Exchange (ETDEWEB)

De Ascencao, Erika M.; Munckton, Toni; Digregorio, Ricardo [Petropiar (Venezuela)

2011-07-01

The Huyapari field, situated within the Faja Petrolifera del Orinoco (FPO) of Venezuela presents unique problems in terms of modeling. This field is spread over a wide area and is therefore subject to variable oil quality and complex fluvial facies architecture. Ameriven and PDVSA have been working on characterizing the ld's reservoirs in this field since 2000 and the aim of this paper is to present these efforts. Among others, a 3-D seismic survey completed in 1998 and a stratigraphic framework built from 149 vertical wells were used for reservoir characterization. Geostatistical techniques such as sequential Gaussian simulation with locally varying mean and cloud transform were also used. Results showed that these geostatistical methods accurately represented the architecture and properties of the reservoir and its fluid distribution. This paper showed that the application of numerous different techniques in the Hamasca area permitted reservoir complexity to be captured.

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.

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.

Marine and fluvial facies modelling at petroleum reservoir scale; Modelisation des heterogeneites lithologiques a l'echelle du reservoir petrolier en milieu marin et fluviatile

Energy Technology Data Exchange (ETDEWEB)

Leflon, B.

2005-10-15

When modelling a petroleum reservoir, well data are very useful to model properties at a sub-seismic scale. Petrophysical properties like porosity or permeability are linked to the rock-type. Two methods based on well data have been developed to model facies. The first one is used to model marine carbonates deposits. The geometry of sedimentary layers is modelled through a special parameterization of the reservoir similar to Wheeler space. The time parameter is defined along the well paths thanks to correlations. The layer thickness is then extrapolated between wells. A given relationship between facies and bathymetry of sedimentation makes it possible to compute bathymetry along the well paths. Bathymetry is then extrapolated from wells and a reference map using the concept of accommodation. The model created this way is stratigraphically consistent. Facies simulation can then be constrained by the computed bathymetry. The second method describes a novel approach to fluvial reservoirs modelling. The core of the method lies in the association of a fairway with the channels to be simulated. Fairways are positioned so that all data are taken in account; they can be stochastic if unknown or explicitly entered if identified on seismic data. A potential field is defined within the fairway. Specifying a transfer function to map this potential field to thickness results in generating a channel inside the fairway. A residual component is stochastically simulated and added to the potential field creating realistic channel geometries. Conditioning to well data is obtained by applying the inverse transfer function at the data location to derive thickness values that will constrain the simulation of residuals. (author)

Sedimentological reservoir characteristics of the Paleocene fluvial/lacustrine Yabus Sandstone, Melut Basin, Sudan

Science.gov (United States)

Mahgoub, M. I.; Padmanabhan, E.; Abdullatif, O. M.

2016-11-01

Melut Basin in Sudan is regionally linked to the Mesozoic-Cenozoic Central and Western African Rift System (CWARS). The Paleocene Yabus Formation is the main oil producing reservoir in the basin. It is dominated by channel sandstone and shales deposited in fluvial/lacustrine environment during the third phase of rifting in the basin. Different scales of sedimentological heterogeneities influenced reservoir quality and architecture. The cores and well logs analyses revealed seven lithofacies representing fluvial, deltaic and lacustrine depositional environments. The sandstone is medium to coarse-grained, poorly to moderately-sorted and sub-angular to sub-rounded, arkosic-subarkosic to sublitharenite. On the basin scale, the Yabus Formation showed variation in sandstone bodies, thickness, geometry and architecture. On macro-scale, reservoir quality varies vertically and laterally within Yabus Sandstone where it shows progressive fining upward tendencies with different degrees of connectivity. The lower part of the reservoir showed well-connected and amalgamated sandstone bodies, the middle to the upper parts, however, have moderate to low sandstone bodies' connectivity and amalgamation. On micro-scale, sandstone reservoir quality is directly affected by textures and diagenetic changes such as compaction, cementation, alteration, dissolution and kaolinite clays pore fill and coat all have significantly reduced the reservoir porosity and permeability. The estimated porosity in Yabus Formation ranges from 2 to 20% with an average of 12%; while permeability varies from 200 to 500 mD and up to 1 Darcy. The understanding of different scales of sedimentological reservoir heterogeneities might contribute to better reservoir quality prediction, architecture, consequently enhancing development and productivity.

Quantifying Evaporation in a Permeable Pavement System

Science.gov (United States)

Studies quantifying evaporation from permeable pavement systems are limited to a few laboratory studies and one field application. This research quantifies evaporation for a larger-scale field application by measuring the water balance from lined permeable pavement sections. Th...

Influence of filling-drawdown cycles of the Vajont reservoir on Mt. Toc slope stability

Science.gov (United States)

Paronuzzi, Paolo; Rigo, Elia; Bolla, Alberto

2013-06-01

In the present work, the 1963 Vajont landslide has been back-analyzed in detail to examine the influence of reservoir operations (filling and drawdown) on Mt. Toc slope stability. The combined seepage-slope stability analyses carried out show that the main destabilizing factor that favored the 1963 Vajont landslide was the reservoir-induced water table that formed as a consequence of rapid seepage inflow within the submerged toe of the slope — decrease in the factor of safety (FOS) up to 12% compared to the initial slope stability condition, i.e., in the absence of the Vajont reservoir. Rainfall would only have been a decisive factor if the initial stability condition of the Mt. Toc slope had already been very close to failure (decrease in FOS caused by heavy or prolonged rainfall is about 3-4%, for the worst case scenario analyzed). The permeability of the shear zone material occurring at the base of the prehistoric Vajont rockslide has been evaluated at 5 × 10- 4 m/s, and back-calculated values of the friction angles Φ range from 17.5° to 27.5°. When considering mountain reservoirs, slope failures can occur during both filling and drawdown phases. In the Vajont case, owing to the highly permeable materials of the shear zone, slope stability decreased during filling and increased during drawdown. Another displacement-dependent phenomenon of a mechanical nature - progressive failure of the NE landslide constraint - has to be considered to understand the slope collapse that occurred during the last drawdown (26 September-9 October 1963). The results of the combined seepage-slope stability models indicate that permeability of bank-forming material and filling-drawdown rates of reservoirs can strongly influence slope stability. Slow lowering of the reservoir level is a necessary measure to reduce the occurrence of very dangerous transient negative peaks of FOS.

Study on the enhancement of hydrocarbon recovery by characterization of the reservoir

Energy Technology Data Exchange (ETDEWEB)

Jeong, Tae-Jin; Kwak, Young-Hoon; Huh, Dae-Gee [Korea Institute of Geology Mining and Materials, Taejon (KR)] (and others)

1999-12-01

The reservoir geochemistry is to understand the origin of these heterogeneities and distributions of the bitumens within the reservoir and to use them not only for exploration but for the development of the petroleums. Methods and principles of the reservoir geochemistry, which are applicable to the petroleum exploration and development, are reviewed in the study. In addition, a case study was carried out on the gas, condensate, water and bitumen samples in the reservoir, taken from the Haenam, Pohang areas and the Ulleung Basin offshore Korea. Mineral geothermometers were studied to estimate the thermal history in sedimentary basins and successfully applied to the Korean onshore and offshore basins. The opal silica-to-quartz transformation was investigated in the Pohang basin as a geothermometer. In Korean basins, the smectite-to-illite changes indicate that smectite and illite can act as the geothermometer to estimate the thermal history of the basins. The albitization reaction was also considered as a temperature indicator. Naturally fractured reservoir is an important source of oil and gas throughout the world. The properties of matrix and fracture are the key parameters in predicting the performances of naturally fractured reservoirs. A new laboratory equipment has been designed and constructed by pressure pulse method to determine the properties, which are (1) the porosity of matrix, (2) the permeability of matrix, (3) the effective width of the fractures, and the permeability of the fractures. (author). 97 refs.

Estimation of In Situ Stress and Permeability from an Extended Leak-off Test

Science.gov (United States)

Nghiep Quach, Quoc; Jo, Yeonguk; Chang, Chandong; Song, Insun

2016-04-01

Among many parameters needed to analyze a variety of geomechanical problems related to subsurface CO2 storage projects, two important ones are in situ stress states and permeability of the storage reservoirs and cap rocks. In situ stress is needed for investigating potential risk of fault slip in the reservoir systems and permeability is needed for assessing reservoir flow characteristics and sealing capability of cap rocks. We used an extended leak-off test (XLOT), which is often routinely conducted to assess borehole/casing integrity as well as fracture gradient, to estimate both in situ least principal stress magnitude and in situ permeability in a CO2 storage test site, offshore southeast Korea. The XLOT was conducted at a casing shoe depth (700 m below seafloor) within the cap rock consisting of mudstone, approximately 50 m above the interface between cap rock and storage reservoir. The test depth was cement-grouted and remained for 4 days for curing. Then the hole was further drilled below the casing shoe to create a 4 m open-hole interval at the bottom. Water was injected using hydraulic pump at an approximately constant flowrate into the bottom interval through the casing, during which pressure and flowrate were recorded continuously at the surface. The interval pressure (P) was increased linearly with time (t) as water was injected. At some point, the slope of P-t curve deviated from the linear trend, which indicates leak-off. Pressure reached its peak upon formation breakdown, followed by a gradual pressure decrease. Soon after the formation breakdown, the hole was shut-in by pump shut-off, from which we determined the instantaneous shut-in pressure (ISIP). The ISIP was taken to be the magnitude of the in situ least principal stress (S3), which was determined to be 12.1 MPa. This value is lower than the lithostatic vertical stress, indicating that the S3 is the least horizontal principal stress. The determined S3 magnitude will be used to characterize the

Effect of cold water injection on operation of and oil production from formations of Romashkino field

Energy Technology Data Exchange (ETDEWEB)

Mingareev, R Sh; Vakhitov, G G; Sultanov, S A

1968-11-01

Each year about 130 million cu m of cold water are injected into this field. Since cold water can lower reservoir temperature, increase oil viscosity, deposit paraffin in the formation, and reduce oil recovery, a thermal survey of this field was conducted. The survey showed that the average reservoir temperature was not reduced by cold-water injection for 15 yr. However, local cooling was observed at distances less than 400 m from the water injection well. Through these wells more than 4 PV of water have passed. The thermal front lags 1,500 m behind the advancing water front. For this reason, cold-water injection does not reduce oil recovery where there is uniform advance of the floodwater. When the formation is heterogeneous so that water advances more rapidly in high-permeability sand than in adjoining low-permeability sand, then the cooling effect can reduce oil recovery. For this reason, it is advisable to force water into the entire interval of the oil formation. An isotherm map of the Romashkino field is shown.

Chalk as a reservoir

DEFF Research Database (Denmark)

Fabricius, Ida Lykke

, and the best reservoir properties are typically found in mudstone intervals. Chalk mudstones vary a lot though. The best mudstones are purely calcitic, well sorted and may have been redeposited by traction currents. Other mudstones are rich in very fine grained silica, which takes up pore space and thus...... basin, so stylolite formation in the chalk is controlled by effective burial stress. The stylolites are zones of calcite dissolution and probably are the source of calcite for porefilling cementation which is typical in water zone chalk and also affect the reservoirs to different extent. The relatively...... have hardly any stylolites and can have porosity above 40% or even 50% and thus also have relatively high permeability. Such intervals have the problem though, that increasing effective stress caused by hydrocarbon production results in mechanical compaction and overall subsidence. Most other chalk...

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.

Full field reservoir modeling of shale assets using advanced data-driven analytics

Directory of Open Access Journals (Sweden)

Soodabeh Esmaili

2016-01-01

Full Text Available Hydrocarbon production from shale has attracted much attention in the recent years. When applied to this prolific and hydrocarbon rich resource plays, our understanding of the complexities of the flow mechanism (sorption process and flow behavior in complex fracture systems - induced or natural leaves much to be desired. In this paper, we present and discuss a novel approach to modeling, history matching of hydrocarbon production from a Marcellus shale asset in southwestern Pennsylvania using advanced data mining, pattern recognition and machine learning technologies. In this new approach instead of imposing our understanding of the flow mechanism, the impact of multi-stage hydraulic fractures, and the production process on the reservoir model, we allow the production history, well log, completion and hydraulic fracturing data to guide our model and determine its behavior. The uniqueness of this technology is that it incorporates the so-called “hard data” directly into the reservoir model, so that the model can be used to optimize the hydraulic fracture process. The “hard data” refers to field measurements during the hydraulic fracturing process such as fluid and proppant type and amount, injection pressure and rate as well as proppant concentration. This novel approach contrasts with the current industry focus on the use of “soft data” (non-measured, interpretive data such as frac length, width, height and conductivity in the reservoir models. The study focuses on a Marcellus shale asset that includes 135 wells with multiple pads, different landing targets, well length and reservoir properties. The full field history matching process was successfully completed using this data driven approach thus capturing the production behavior with acceptable accuracy for individual wells and for the entire asset.

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

Modeling reservoir geomechanics using discrete element method : Application to reservoir monitoring

Energy Technology Data Exchange (ETDEWEB)

Alassi, Haitham Tayseer

2008-09-15

Understanding reservoir geomechanical behavior is becoming more and more important for the petroleum industry. Reservoir compaction, which may result in surface subsidence and fault reactivation, occurs during reservoir depletion. Stress changes and possible fracture development inside and outside a depleting reservoir can be monitored using time-lapse (so-called '4D') seismic and/or passive seismic, and this can give valuable information about the conditions of a given reservoir during production. In this study we will focus on using the (particle-based) Discrete Element Method (DEM) to model reservoir geomechanical behavior during depletion and fluid injection. We show in this study that DEM can be used in modeling reservoir geomechanical behavior by comparing results obtained from DEM to those obtained from analytical solutions. The match of the displacement field between DEM and the analytical solution is good, however there is mismatch of the stress field which is related to the way stress is measured in DEM. A good match is however obtained by measuring the stress field carefully. We also use DEM to model reservoir geomechanical behavior beyond the elasticity limit where fractures can develop and faults can reactivate. A general technique has been developed to relate DEM parameters to rock properties. This is necessary in order to use correct reservoir geomechanical properties during modeling. For any type of particle packing there is a limitation that the maximum ratio between P- and S-wave velocity Vp/Vs that can be modeled is 3 . The static behavior for a loose packing is different from the dynamic behavior. Empirical relations are needed for the static behavior based on numerical test observations. The dynamic behavior for both dense and loose packing can be given by analytical relations. Cosserat continuum theory is needed to derive relations for Vp and Vs. It is shown that by constraining the particle rotation, the S-wave velocity can be

INTEGRATED GEOLOGIC-ENGINEERING MODEL FOR REEF AND CARBONATE SHOAL RESERVOIRS ASSOCIATED WITH PALEOHIGHS: UPPER JURASSIC SMACKOVER FORMATION, NORTHEASTERN GULF OF MEXICO

Energy Technology Data Exchange (ETDEWEB)

Ernest A. Mancini

2003-09-25

processes influencing pore system development and heterogeneity in these reef and shoal reservoirs have been made. Petrophysical and engineering property characterization has been completed. Porosity and permeability data at Appleton and Vocation Fields have been analyzed, and well performance analysis has been conducted. Data integration is up to date, in that, the geological, geophysical, petrophysical and engineering data collected to date for Appleton and Vocation Fields have been compiled into a fieldwide digital database. 3-D geologic modeling of the structures and reservoirs at Appleton and Vocation Fields has been completed. The models represent an integration of geological, petrophysical and seismic data. 3-D reservoir simulation of the reservoirs at Appleton and Vocation Fields has been completed. The 3-D geologic models served as the framework for the simulations. The geologic-engineering models of the Appleton and Vocation Field reservoirs have been developed. These models are being tested. The geophysical interpretation for the paleotopographic feature being tested has been made, and the study of the data resulting from drilling of a well on this paleohigh is in progress. Numerous presentations on reservoir characterization and modeling at Appleton and Vocation Fields have been made at professional meetings and conferences and a short course on microbial reservoir characterization and modeling based on these fields has been prepared.

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

First field example of remediation of unwanted migration from a natural CO2 reservoir: The Bečej Field, Serbia

NARCIS (Netherlands)

Karas, D.; Demić, I.; Kultysheva, K.; Antropov, A.; Blagojević, M.; Neele, F.; Pluymaekers, M.; Orlić, B.

2016-01-01

The Bečej field, discovered in 1951 by the Petroleum Industry of Serbia (NIS), is one of the largest natural CO2 fields in Europe. Uncontrolled migration of CO2 out of the main reservoir, leading to subsurface seepage and surface leakage, was caused by the Bč-5 well blowout in 1968. Remediation

Reservoir Changes Derived from Seismic Observations at The Geysers Geothermal Field, CA, USA

Science.gov (United States)

Gritto, R.; Jarpre, S.

2012-04-01

Induced seismicity associated with the exploitation of geothermal fields is used as a tool to characterize and delineate changes associated with injection and production of fluids from the reservoir. At the same time public concern of felt seismicity has led to objections against the operation of geothermal reservoirs in close proximity to population centers. Production at the EGS sites in Basel (Switzerland) was stopped after renewed seismicity caused concern and objection from the public in the city. Operations in other geothermal reservoirs had to be scaled back or interrupted due to an unexpected increase in seismicity (Soultz-sous-forêt, France, Berlín, El Salvador). As a consequence of these concerns and in order to optimize the use of induced seismicity for reservoir engineering purposes, it becomes imperative to understand the relationship between seismic events and stress changes in the reservoir. We will address seismicity trends at The Geysers Geothermal Reservoir, CA USA, to understand the role of historical seismicity associated with past injection of water and/or production of steam. Our analysis makes use of a comprehensive database of earthquakes and associated phase arrivals from 2004 to 2011. A high-precision sub-set of the earthquake data was selected to analyze temporal changes in seismic velocities and Vp/Vs-ratio throughout the whole reservoir. We find relatively low Vp/Vs values in 2004 suggestive of a vapor dominated reservoir. With passing time, however, the observed temporal increase in Vp/Vs, coupled with a decrease in P- and S-wave velocities suggests the presence of fluid-filled fractured rock. Considering the start of a continuous water injection project in 2004, it can be concluded that the fluid saturation of the reservoir has successfully recovered. Preliminary results of 3-D velocity inversions of seismic data appear to corroborate earlier findings that the lowest Vp/Vs estimates are observed in the center of the reservoir

Static reservoir modeling of the Bahariya reservoirs for the oilfields development in South Umbarka area, Western Desert, Egypt

Science.gov (United States)

Abdel-Fattah, Mohamed I.; Metwalli, Farouk I.; Mesilhi, El Sayed I.

2018-02-01

3D static reservoir modeling of the Bahariya reservoirs using seismic and wells data can be a relevant part of an overall strategy for the oilfields development in South Umbarka area (Western Desert, Egypt). The seismic data is used to build the 3D grid, including fault sticks for the fault modeling, and horizon interpretations and surfaces for horizon modeling. The 3D grid is the digital representation of the structural geology of Bahariya Formation. When we got a reasonably accurate representation, we fill the 3D grid with facies and petrophysical properties to simulate it, to gain a more precise understanding of the reservoir properties behavior. Sequential Indicator Simulation (SIS) and Sequential Gaussian Simulation (SGS) techniques are the stochastic algorithms used to spatially distribute discrete reservoir properties (facies) and continuous reservoir properties (shale volume, porosity, and water saturation) respectively within the created 3D grid throughout property modeling. The structural model of Bahariya Formation exhibits the trapping mechanism which is a fault assisted anticlinal closure trending NW-SE. This major fault breaks the reservoirs into two major fault blocks (North Block and South Block). Petrophysical models classified Lower Bahariya reservoir as a moderate to good reservoir rather than Upper Bahariya reservoir in terms of facies, with good porosity and permeability, low water saturation, and moderate net to gross. The Original Oil In Place (OOIP) values of modeled Bahariya reservoirs show hydrocarbon accumulation in economic quantity, considering the high structural dips at the central part of South Umbarka area. The powerful of 3D static modeling technique has provided a considerable insight into the future prediction of Bahariya reservoirs performance and production behavior.

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.

The internal wave field in Sau reservoir : Observation and modeling of a third vertical mode

OpenAIRE

Vidal Hurtado, Javier; Casamitjana, Xavier; Colomer, Jordi; Serra Putellas, Teresa

2005-01-01

Water withdrawal from Mediterranean reservoirs in summer is usually very high. Because of this, stratification is often continuous and far from the typical two-layered structure, favoring the excitation of higher vertical modes. The analysis of wind, temperature, and current data from Sau reservoir (Spain) shows that the third vertical mode of the internal seiche (baroclinic mode) dominated the internal wave field at the beginning of September 2003. We used a continuous stratification two-dim...

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)

Thermochemical sulphate reduction can improve carbonate petroleum reservoir quality

Science.gov (United States)

Jiang, Lei; Worden, Richard H.; Yang, Changbing

2018-02-01

Interest in the creation of secondary pore spaces in petroleum reservoirs has increased because of a need to understand deeper and more complex reservoirs. The creation of new secondary porosity that enhances overall reservoir quality in deeply buried carbonate reservoirs is controversial and some recent studies have concluded it is not an important phenomenon. Here we present petrography, geochemistry, fluid inclusion data, and fluid-rock interaction reaction modeling results from Triassic Feixianguan Formation, Sichuan Basin, China, core samples and explore the relative importance of secondary porosity due to thermochemical sulphate reduction (TSR) during deep burial diagenesis. We find that new secondary pores result from the dissolution of anhydrite and possibly from dissolution of the matrix dolomite. Assuming porosity before TSR was 16% and the percentage of anhydrite was 6%, modelling shows that, due to TSR, 1.6% additional porosity was created that led to permeability increasing from 110 mD (range 72-168 mD within a 95% confidence interval) to 264 mD (range 162-432 mD within a 95% confidence interval). Secondary porosity results from the density differences between reactant anhydrite and product calcite, the addition of new water during TSR, and the generation of acidity during the reaction of new H2S with the siderite component in pre-existing dolomite in the reservoir. Fluid pressure was high during TSR, and approached lithostatic pressure in some samples; this transient overpressure may have led to the maintenance of porosity due to the inhibition of compactional processes. An additional 1.6% porosity is significant for reserve calculations, especially considering that it occurs in conjunction with elevated permeability that results in faster flow rates to the production wells.

) Ima Field: A Type Marginal Field-Challenges and Prospects

International Nuclear Information System (INIS)

Afolabi, T. J.

2003-01-01

The IMA Field is located in the south-eastern Niger Delta in approximately 30' of water. Discovered in 1972 by Japan Petroleum, commercial accumulation was not established until 1994 by the AMNI/Abacan Joint Venture, with the drilling of ima-3 well, which discovered the major reservoirs in the C and D sands. Recoverable Reserve of 48MMBO. Ten wells have been drilled on the IMA structure to date, with a cumulative production of 16 Million barrels of condensates.The IMA Field is a typical Niger Delta rollover anticlinal structure trending northeast southwest with a regional tilt to the northeast. The major trapping mechanism is the anticline.The sediments of IMA Field are Miocene Agbada Fm. They are deltaic deposits with high sand/shale ratio. The reservoirs are loosely compacted sandstones with porosity values ranging from 21% to 27% while permeability is generally measured in darcies.The development of IMA Field posed financial and logistical challenges since the partners had decided to fast track this process, and since neither had the resources to drill the development wells, assemble/install the crude processing and storage facilities; a mixture of debt financing and contractor financing arrangements were made.The prospects in IMA Field are to be found in early realisation of the limitations of a marginal field, particularly the management of cash flow. Workers and field development funding is financed by current production. Appraisal and exploration drilling within the same lease have required equity financing (participation)

Simple algorithm to estimate mean-field effects from minor differential permeability curves based on the Preisach model

International Nuclear Information System (INIS)

Perevertov, Oleksiy

2003-01-01

The classical Preisach model (PM) of magnetic hysteresis requires that any minor differential permeability curve lies under minor curves with larger field amplitude. Measurements of ferromagnetic materials show that very often this is not true. By applying the classical PM formalism to measured minor curves one can discover that it leads to an oval-shaped region on each half of the Preisach plane where the calculations produce negative values in the Preisach function. Introducing an effective field, which differs from the applied one by a mean-field term proportional to the magnetization, usually solves this problem. Complex techniques exist to estimate the minimum necessary proportionality constant (the moving parameter). In this paper we propose a simpler way to estimate the mean-field effects for use in nondestructive testing, which is based on experience from the measurements of industrial steels. A new parameter (parameter of shift) is introduced, which monitors the mean-field effects. The relation between the shift parameter and the moving one was studied for a number of steels. From preliminary experiments no correlation was found between the shift parameter and the classical magnetic ones such as the coercive field, maximum differential permeability and remanent magnetization

The Controls of Pore-Throat Structure on Fluid Performance in Tight Clastic Rock Reservoir: A Case from the Upper Triassic of Chang 7 Member, Ordos Basin, China

Directory of Open Access Journals (Sweden)

Yunlong Zhang

2018-01-01

Full Text Available The characteristics of porosity and permeability in tight clastic rock reservoir have significant difference from those in conventional reservoir. The increased exploitation of tight gas and oil requests further understanding of fluid performance in the nanoscale pore-throat network of the tight reservoir. Typical tight sandstone and siltstone samples from Ordos Basin were investigated, and rate-controlled mercury injection capillary pressure (RMICP and nuclear magnetic resonance (NMR were employed in this paper, combined with helium porosity and air permeability data, to analyze the impact of pore-throat structure on the storage and seepage capacity of these tight oil reservoirs, revealing the control factors of economic petroleum production. The researches indicate that, in the tight clastic rock reservoir, largest throat is the key control on the permeability and potentially dominates the movable water saturation in the reservoir. The storage capacity of the reservoir consists of effective throat and pore space. Although it has a relatively steady and significant proportion that resulted from the throats, its variation is still dominated by the effective pores. A combination parameter (ε that was established to be as an integrated characteristic of pore-throat structure shows effectively prediction of physical capability for hydrocarbon resource of the tight clastic rock reservoir.

Predicting Porosity and Permeability for the Canyon Formation, SACROC Unit (Kelly-Snyder Field), Using the Geologic Analysis via Maximum Likelihood System

International Nuclear Information System (INIS)

Reinaldo Gonzalez; Scott R. Reeves; Eric Eslinger

2007-01-01

-based, probabilistic clustering analysis procedure is successfully applied to generate a high-resolution reservoir characterization outcome. The approach was applied in the Pennsylvanian-Permian reef carbonates (Cisco and Canyon Formations) of a subregion of the SACROC Unit, Horseshoe Atoll, Permian Basin, Texas, and acknowledged as a highly complex carbonate reservoir. Due to the modest results achieved with the application of soft-computing methodologies to the available information (no crosswell data at hand), the original project target about creating a data-driven device relating surface seismic information, crosswell seismic attributes, geophysical logs and core parameters for the prediction of core-scale porosity and permeability profiles in locations where only 3D surface seismic data was available, had to be reformulated. It was shown that 3D seismic information was not capable of capturing the degree of vertical variability of SACROC. As a consequence, available seismic information was unincorporated from posterior reservoir characterization tasks, and a combination of data-driven procedures and geostatistical methods was utilized for reservoir characterization purposes. A selected area within the SACROC Unit platform was used for this study. The suitable logs for the creation of an 'intelligent' log-to-core device were not present for all wells. These logs were gamma ray (GR), neutron porosity (NPHI), bulk density (RHOB), and delta time (DT). It was necessary to create a first 'intelligent' tool, a log-to-log model to provide synthetic logs of RHOB and DT (or eventually of acoustic impedance derived from them) at well locations where only GR and NPHI were available (the most common situation in this reservoir). Once the 'ideal' logs were completed, a second model, a log-to-core device, provides core scale estimates of porosity and permeability (P and P). The validity of these soft-computing devices was checked using 'holdout' wells. In this way, 'core' parameter profiles

Measurements of gas permeability and non-Darcy flow in gas-water-hydrate systems

Energy Technology Data Exchange (ETDEWEB)

Ersland, G.; Husebo, J.; Graue, A.; Kvamme, B. [Bergen Univ., Bergen (Norway). Dept. of Physics and Technology; Baldwin, B. [Green Country Petrophysics LLC, Dewey, OK (United States); Stevens, J.; Howard, J. [ConocoPhillips, OK (United States)

2008-07-01

Storage of carbon dioxide (CO{sub 2}) in natural gas hydrate reservoirs may offer stable long-term storage of a greenhouse gas while benefiting from methane production, without requiring heat. By exposing hydrate to a thermodynamically preferred hydrate former, CO{sub 2}, the hydrate may be maintained macroscopically in the solid state and retain the stability of the formation. However, there is concern over the flow capacity in such reservoirs. This depends on several factors, notably thermodynamic destabilization of hydrate in small pores due to capillary effects; the presence of liquid channels separating the hydrate from the mineral surfaces; and, the connectivity of gas or liquid filled pores and channels. This paper described a technique for measuring gas permeability in gas-water-hydrate systems. It reported on several experiments that measured gas permeability during stages of hydrate growth in sandstone core plugs. Interactions between minerals and surrounding molecules were also discussed. The formation of methane hydrate in porous media was monitored and quantified with magnetic resonance imaging (MRI). MRI images of hydrate growth within the porous rock were provided along with measurements of gas permeability and non-Darcy flow effects at various hydrate saturations. Gas permeability was measured at steady state flow of methane through the hydrate-bearing core sample. Significant gas permeability was recorded for porous sandstone even when hydrates occupied up to 60 per cent of the pore space. It was concluded that MRI imaging can be used effectively to map and quantify hydrate saturation in sandstone core plugs. 27 refs., 2 tabs., 10 figs.

MULTI-ATTRIBUTE SEISMIC/ROCK PHYSICS APPROACH TO CHARACTERIZING FRACTURED RESERVOIRS

Energy Technology Data Exchange (ETDEWEB)

Gary Mavko

2000-10-01

This project consists of three key interrelated Phases, each focusing on the central issue of imaging and quantifying fractured reservoirs, through improved integration of the principles of rock physics, geology, and seismic wave propagation. This report summarizes the results of Phase I of the project. The key to successful development of low permeability reservoirs lies in reliably characterizing fractures. Fractures play a crucial role in controlling almost all of the fluid transport in tight reservoirs. Current seismic methods to characterize fractures depend on various anisotropic wave propagation signatures that can arise from aligned fractures. We are pursuing an integrated study that relates to high-resolution seismic images of natural fractures to the rock parameters that control the storage and mobility of fluids. Our goal is to go beyond the current state-of-the art to develop and demonstrate next generation methodologies for detecting and quantitatively characterizing fracture zones using seismic measurements. Our study incorporates 3 key elements: (1) Theoretical rock physics studies of the anisotropic viscoelastic signatures of fractured rocks, including up scaling analysis and rock-fluid interactions to define the factors relating fractures in the lab and in the field. (2) Modeling of optimal seismic attributes, including offset and azimuth dependence of travel time, amplitude, impedance and spectral signatures of anisotropic fractured rocks. We will quantify the information content of combinations of seismic attributes, and the impact of multi-attribute analyses in reducing uncertainty in fracture interpretations. (3) Integration and interpretation of seismic, well log, and laboratory data, incorporating field geologic fracture characterization and the theoretical results of items 1 and 2 above. The focal point for this project is the demonstration of these methodologies in the Marathon Oil Company Yates Field in West Texas.

Biocompetitive exclusion technology: A field system to control reservoir souring and increasing production

Energy Technology Data Exchange (ETDEWEB)

Sandbeck, K.A.; Hitzman, D.O.

1995-12-31

Biogenic formation of sulfide in reservoirs by Sulfate Reducing Bacteria (SRB) causes serious plugging, corrosion, and environmental safety problems. The production of sulfide can be decreased, and its concentration reduced, by the establishment and growth of an indigenous microbial population which results in a replacement of the SRB population. This approach to modify the reservoir ecology utilizing preexisting carbon sources coupled with the introduction of an alternate electron acceptor forms the basis of a new Biocompetitive Exclusion technology which has the potential to enhance oil recovery and decrease paraffin deposition and corrosion. Preliminary field results from an ongoing DOE-sponsored research program will be discussed.

Inverse modeling and forecasting for the exploitation of the Pauzhetsky geothermal field, Kamchatka, Russia

Energy Technology Data Exchange (ETDEWEB)

Finsterle, Stefan; Kiryukhin, A.V.; Asaulova, N.P.; Finsterle, S.

2008-04-01

A three-dimensional numerical model of the Pauzhetsky geothermal field has been developed based on a conceptual hydrogeological model of the system. It extends over a 13.6-km2 area and includes three layers: (1) a base layer with inflow; (2) a geothermal reservoir; and (3) an upper layer with discharge and recharge/infiltration areas. Using the computer program iTOUGH2 (Finsterle, 2004), the model is calibrated to a total of 13,675 calibration points, combining natural-state and 1960-2006 exploitation data. The principal model parameters identified and estimated by inverse modeling include the fracture permeability and fracture porosity of the geothermal reservoir, the initial natural upflow rate, the base-layer porosity, and the permeabilities of the infiltration zones. Heat and mass balances derived from the calibrated model helped identify the sources of the geothermal reserves in the field. With the addition of five makeup wells, simulation forecasts for the 2007-2032 period predict a sustainable average steam production of 29 kg/s, which is sufficient to maintain the generation of 6.8 MWe at the Pauzhetsky power plant.

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)

Some characteristics in operation of long exploited oil fields in Fergana depression. [USSR

Energy Technology Data Exchange (ETDEWEB)

Gordinskii, E V; Ovanesov, M G; Irmatov, E K

1969-01-01

A review of geological and oil production data from 3 Fergana fields is presented. The reservoirs are small, tectonically bounded, and are anticlines of Paleogenic carbonates. Reservoirs are heterogeneous with porosity ranging from 3 to 25% and permeability ranging from a few to 500 md. Some of the reservoirs have expanding gas caps, some are solution drive, and others have been waterflooded. All are now in the final stage of depletion. Production history and characteristics of each group are given. One way of increasing present production rate appears to be injection of gas or air into the reservoirs. This can be done inexpensively, since additional injection wells would not have to be drilled and some produced gas is available. Increased fluid withdrawal from present wells should also be beneficial.

Reservoir Characterization and CO2 Plume Migration Modeling Based on Bottom-hole Pressure Data: An Example from the AEP Mountaineer Geological Storage Project

Science.gov (United States)

Mishra, Srikanta; Kelley, Mark; Oruganti, YagnaDeepika; Bhattacharya, Indra; Spitznogle, Gary

2014-05-01

-invasive strategy for inferring the extent of the CO2 plume from the analysis of pressure monitoring data. Application of this methodology to the Rose Run data indicates a two-zone permeability model for the undisturbed formation, as well as an estimate of CO2 front movement over time. For reservoir modeling, a 2-D radial-cylindrical model based on "average" conditions in the study area was developed from integration of well-log and seismic data. STOMP-CO2 simulations were carried out to calibrate the observed pressure response using a trial-and-error procedure. This involved varying: (1) permeability near the injection well, (2) permeability of the far-field region, and (3) relative permeability model coefficients. Non-unique combinations of these parameters were found to produce similar pressure match, but different estimates of plume migration. Excellent matches were obtained for the bottom-hole pressures both at the injection well and the monitoring well using a two-zone permeability model, which corroborates the transient pressure analysis results. Estimates of radial plume migration, using the calibrated model, also agree well with those from the front tracking method described earlier.

The Ardross reservoir gridblock analogue: Sedimentology, statistical representivity, and flow upscaling

Energy Technology Data Exchange (ETDEWEB)

Ringrose, P.; Pickup, G.; Jensen, J. [Heriot-Watt Univ., Edinburgh (United Kingdom)] [and others

1997-08-01

We have used a reservoir gridblock-sized outcrop (10m by 100m) of fluvio-deltaic sandstones to evaluate the importance of internal heterogeneity for a hypothetical waterflood displacement process. Using a dataset based on probe permeameter measurements taken from two vertical transacts representing {open_quotes}wells{close_quotes} (5cm sampling) and one {open_quotes}core{close_quotes} sample (exhaustive 1mm-spaced sampling), we evaluate the permeability variability at different lengthscales, the correlation characteristics (structure of the variogram, function), and larger-scale trends. We then relate these statistical measures to the sedimentology. We show how the sediment architecture influences the effective tensor permeability at the lamina and bed scale, and then calculate the effective relative permeability functions for a waterflood. We compare the degree of oil recovery from the formation: (a) using averaged borehole data and no geological structure, and (b) modelling the sediment architecture of the interwell volume using mixed stochastic/deterministic methods. We find that the sediment architecture has an important effect on flow performance, mainly due to bedscale capillary trapping and a consequent reduction in the effective oil mobility. The predicted oil recovery differs by 18% when these small-scale effects are included in the model. Traditional reservoir engineering methods, using averages permeability values, only prove acceptable in high-permeability and low-heterogeneity zones. The main outstanding challenge, represented by this illustration of sub-gridblock scale heterogeneity, is how to capture the relevant geological structure along with the inherent geo-statistical variability. An approach to this problem is proposed.

Computerized X-ray Microtomography Observations and Fluid Flow Measurements of the Effect of Effective Stress on Fractured Reservoir Seal Shale

Science.gov (United States)

Welch, N.; Crawshaw, J.; Boek, E.

2014-12-01

The successful storage of carbon dioxide in geologic formations requires an in-depth understanding of all reservoir characteristics and morphologies. An intact and substantial seal formation above a storage reservoir is required for a significant portion of the initial sealing mechanisms believed to occur during carbon dioxide storage operations. Shales are a common seal formation rock types found above numerous hydrocarbon reservoirs, as well as potential saline aquifer storage locations. Shales commonly have very low permeability, however they also have the tendency to be quite fissile, and the formation of fractures within these seals can have a significant detrimental effect on the sealing potential of a reservoir and amount to large areas of high permeability and low capillary pressures compared to the surrounding intact rock. Fractured shales also have an increased current interest due to the increasing development of shale gas reservoirs using hydraulic fracturing techniques. This work shows the observed changes that occur within fractured pieces of reservoir seal shale samples, along with quarry analogues, using an in-situ micro-CT fluid flow imaging apparatus with a Hassler type core holder. Changes within the preferential flow path under different stress regimes as well as physical changes to the fracture geometry are reported. Lattice Boltzmann flow simulations were then performed on the extracted flow paths and compared to experiment permeability measurements. The preferential flow path of carbon dioxide through the fracture network is also observed and compared to the results two-phase Lattice Boltzmann fluid flow simulations.

Interaction between Proppant Packing, Reservoir Depletion, and Fluid Flow in Pore Space

Science.gov (United States)

Fan, M.; McClure, J. E.; Han, Y.; Chen, C.

2016-12-01

In the oil and gas industry, the performance of proppant pack in hydraulically created fractures has a significant influence on fracture conductivity. A better understanding of proppant transport and deposition pattern in a hydraulic fracture is vital for effective and economical production within oil and gas reservoirs. In this research, a numerical modeling approach, combining Particle Flow Code (PFC) and GPU-enhanced lattice Boltzmann simulator (GELBS), is adopted to advance the understanding of the interaction between proppant particle packing, depletion of reservoir formation, and transport of reservoir flow through the pore space. In this numerical work flow, PFC is used to simulate effective stress increase and proppant particle movement and rearrangement under increasing mechanical loading. The pore structure of the proppant pack evolves subsequently and the geometrical data are output for lattice Boltzmann (LB) simulation of proppant pack permeability. Three different proppant packs with fixed particle concentration and 12/18, 16/30, and 20/40 mesh sizes are generated. These proppant packs are compressed with specified loading stress and their subsequent geometries are used for fluid flow simulations. The simulation results are in good agreement with experimental observations, e.g., the conductivity of proppant packs decreases with increasing effective stress. Three proppant packs with the same average diameter were generated using different coefficients of variation (COVs) for the proppant diameter (namely cov5%, cov20%, and cov30%). By using the coupled PFC-LBM work flow, the proppant pack permeability as functions of effective stress and porosity is investigated. The results show that the proppant pack with a higher proppant diameter COV has lower permeability and porosity under the same effective stress, because smaller particles fill in the pore space between bigger particles. The relationship between porosity and permeability is also consistent with

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

Modeling stress/strain-dependent permeability changes for deep geoenergy applications

Science.gov (United States)

Rinaldi, Antonio Pio; Rutqvist, Jonny

2016-04-01

Rock permeability is a key parameter in deep geoenergy systems. Stress and strain changes induced at depth by fluid injection or extraction may substantially alter the rock permeability in an irreversible way. With regard to the geoenergies, some applications require the permeability to be enhanced to improve productivity. The rock permeability is generally enhanced by shearing process of faults and fractures (e.g. hydroshearing for Enhanced and Deep Geothermal Systems), or the creation of new fractures (e.g. hydrofracturing for shale gas). However, such processes may, at the same time, produce seismicity that can be felt by the local population. Moreover, the increased permeability due to fault reactivation may pose at risk the sealing capacity of a storage site (e.g. carbon sequestration or nuclear waste disposal), providing then a preferential pathway for the stored fluids to escape at shallow depth. In this work we present a review of some recent applications aimed at understanding the coupling between stress (or strain) and permeability. Examples of geoenergy applications include both EGS and CO2 sequestration. To investigate both "wanted" and "unwanted" effects, THM simulations have been carried out with the TOUGH-FLAC simulator. Our studies include constitutive equations relating the permeability to mean effective stress, effective normal stress, volumetric strain, as well as accounting for permeability variation as related to fault/fracture reactivation. Results show that the geomechanical effects have a large role in changing the permeability, hence affecting fluids leakage, reservoir enhancement, as well as the induced seismicity.

Low power loss and field-insensitive permeability of Fe-6.5%Si powder cores with manganese oxide-coated particles

Energy Technology Data Exchange (ETDEWEB)

Li, Junnan, E-mail: junnanli1991@163.com, E-mail: rzhgong@hust.edu.cn; Wang, Xian; Xu, Xiaojun; Gong, Rongzhou, E-mail: junnanli1991@163.com, E-mail: rzhgong@hust.edu.cn; Feng, Zekun [School of Optical and Electronic Information, Huazhong University of Science and Technology, Wuhan 430074 (China); Chen, Yajie; Harris, V. G. [Department of Electrical and Computer Engineering, Center for Microwave Magnetic Materials and Integrated Circuits, Northeastern University, Boston, Massachusetts 02115 (United States)

2015-05-07

Fe-6.5%Si alloy powders coated with manganese oxides using an innovative in situ process were investigated. The in-situ coating of the insulating oxides was realized with a KMnO{sub 4} solution by a chemical process. The insulating manganese oxides with mixed valance state were verified by X-ray photoelectron spectroscopy analysis. The thickness of the insulating layer on alloy particles was determined to be in a range of 20–210 nm, depending upon the KMnO{sub 4} concentration. The powder core loss and the change in permeability under a DC-bias field were measured at frequencies ranging from 50 to 100 kHz. The experiments indicated that the Fe-6.5%Si powder cores with a 210 nm-thick manganese oxide layer not only showed a low core loss of 459 mW/cm{sup 3} at 100 kHz but also showed a small reduction in permeability (μ(H)/μ(0) = 85% for μ = 42) at a DC-bias field of 80 Oe. This work has defined a novel pathway to realizing low core loss and field-insensitive permeability for Fe-Si powder cores.

Cross-flow analysis of injection wells in a multilayered reservoir

Directory of Open Access Journals (Sweden)

Mohammadreza Jalali

2016-09-01

Natural and forced cross-flow is modeled for some injection wells in an oil reservoir located at North Sea. The solution uses a transient implicit finite difference approach for multiple sand layers with different permeabilities separated by impermeable shale layers. Natural and forced cross-flow rates for each reservoir layer during shut-in are calculated and compared with different production logging tool (PLT measurements. It appears that forced cross-flow is usually more prolonged and subject to a higher flow rate when compared with natural cross-flow, and is thus worthy of more detailed analysis.

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

Petroleum Characterisation and Reservoir Dynamics - The Froey Field and the Rind Discovery, Norwegian Continental Shelf

Energy Technology Data Exchange (ETDEWEB)

Bhullar, Abid G.

1999-07-01

The objective of this thesis is to apply the fundamental principles of petroleum geochemistry integrated with petroleum/reservoir engineering and geological concepts to the dynamics and characterisation of petroleum reservoirs. The study is based on 600 core samples and 9 DST oils from 11 wells in the Froey Field and the Rind Discovery. The work is presented in five papers. Paper 1 is a detailed characterisation of the reservoirs using a petroleum geochemical approach. Paper 2 describes the application of a single reservoir geochemical screening technique to exploration, appraisal and production geology and reservoir/petroleum engineering. Paper 3 compares the Iatroscan TLC-FID screening technique and the extraction efficiency of micro-extraction used in this work with the well-established Rock-Eval geochemical screening method and with the Soxtec extraction method. Paper 4 refines the migration and filling models of Paper 1, and Paper 5 presents a comparison of models of petroleum generation, migration and accumulation based on geochemical data with 1D burial history, a ''pseudo well'' based on actual well data and regional seismic analysis representing the hydrocarbon generative basin conditions.

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.

[Dynamics of soil water reservoir of wheat field in rain-fed area of the Loess Tableland, China].

Science.gov (United States)

Li, Peng Zhan; Wang, Li; Wang, Di

2017-11-01

Soil reservoir is the basis of stable grain production and sustainable development in dry farming area. Based on the long-term field experiment, this paper investigated the changes of soil moisture in wheat field located in the rain-fed Changwu Tableland, and analyzed the interannual and annual variation characteristics and dynamics trends of soil reservoir from 2012 to 2015. The results showed that the vertical distribution curves of average soil water content were double peaks and double valleys: first peak and valley occurred in the 10-20 and 50 cm soil layer, respectively, while for the second peak and valley, the corresponding soil layer was the 100 and 280 cm soil layer. Soil reservoir did not coincide with precipitation for all yearly precipitation patterns but lagged behind. Yearly precipitation patterns had a great influence on the interannual and annual dynamic changes of soil reservoir. Compared with rainy year, the depth of soil moisture consumption decreased and supplementary effect of precipitation on soil moisture became obvious under effects of drought year and normal year. In rainy year, soil reservoir had a large surplus (84.2 mm), water balance was compensated; in normal year, it had a slight surplus (9.5 mm), water balance was compensated; while in drought year, it was slightly deficient (1.5 mm), water balance was negatively compensated. The dynamics of soil water in winter wheat field in the rain-fed Changwu Tableland could be divided into four periods: seedling period, slow consumption period, large consumption period, and harvest period, the order of evapotranspiration was large consumption period> seedling period> harvest period> slow consumption period.

Fractured reservoirs - Indication from the EGS at Soultz

Science.gov (United States)

Schill, E.; Kümmritz, J.; Geiermann, J.

2009-04-01

and permeability changes in EGS fields and thus to provide more information on the fractured reservoir. For the inversion earlier gravity data (summarized in the FIS Geophysik, GGA Hannover, and from BRGM Strassbourg) were interpolated on a 200 m grid. In order to account for the astenosphere anomaly below the Upper Rhine valley a Butterworth filter with a wave length of 80 km was applied. For the inversion of the data a geological 3D model was discretized in a 3D voxel raster. The inversion was carried out with 3D Geomodeller based on the apporach of Mosegaard and Tarantola, 1995). The inversion results show a zone of relativly lower density of about 2500 kg m-3 in the horst of Soultz in respect to the surrounding granitic basement of about 3000 kg m-3, which can be attributed to a increase in porosity in the Soultz horst. In order to investigate this observation more in detail, a 2D MT survey has been carried out on a E-W profile across the Soultz horst approximately on the latitude of GPK4. Along approximately 10 km long profile 13 stations have been measuring for approximately 2 days. A number of 7 stations have been operated with a remote reference station at Vogelsberg (Germany). Using remote referencing, 10 stations could be used for 2D inversion in the period range of 0.06 to 40 s. Before inversion, the stations have been rotated the 52° and Sutarno phase consistent smoothing has been applied. For the inversion an a priori model incorporating the major geological structures of the Rhine valley has been used. The inversion process has been set to minimize deviation from the starting model. The inversion result reveals a zone of high electric conductivity of about 3 Ωm between the Soultz and Kutzenhausen fault. This high electric conductivity can be attributed to major fluid flow in the area around the two faults, thus indicating enhanced permeability. In the granite, those low resistivities can only be explained by interconnected pore space. In conclusion

Reservoir characterization and final pre-test analysis in support of the compressed-air-energy-storage Pittsfield aquifer field test in Pike County, Illinois

Energy Technology Data Exchange (ETDEWEB)

Wiles, L.E.; McCann, R.A.

1983-06-01

The work reported is part of a field experimental program to demonstrate and evaluate compressed air energy storage in a porous media aquifer reservoir near Pittsfield, Illinois. The reservoir is described. Numerical modeling of the reservoir was performed concurrently with site development. The numerical models were applied to predict the thermohydraulic performance of the porous media reservoir. This reservoir characterization and pre-test analysis made use of evaluation of bubble development, water coning, thermal development, and near-wellbore desaturation. The work was undertaken to define the time required to develop an air storage bubble of adequate size, to assess the specification of instrumentation and above-ground equipment, and to develop and evaluate operational strategies for air cycling. A parametric analysis was performed for the field test reservoir. (LEW)

The seismo-hydromechanical behavior during deep geothermal reservoir stimulations: open questions tackled in a decameter-scale in situ stimulation experiment

Science.gov (United States)

Amann, Florian; Gischig, Valentin; Evans, Keith; Doetsch, Joseph; Jalali, Reza; Valley, Benoît; Krietsch, Hannes; Dutler, Nathan; Villiger, Linus; Brixel, Bernard; Klepikova, Maria; Kittilä, Anniina; Madonna, Claudio; Wiemer, Stefan; Saar, Martin O.; Loew, Simon; Driesner, Thomas; Maurer, Hansruedi; Giardini, Domenico

2018-02-01

In this contribution, we present a review of scientific research results that address seismo-hydromechanically coupled processes relevant for the development of a sustainable heat exchanger in low-permeability crystalline rock and introduce the design of the In situ Stimulation and Circulation (ISC) experiment at the Grimsel Test Site dedicated to studying such processes under controlled conditions. The review shows that research on reservoir stimulation for deep geothermal energy exploitation has been largely based on laboratory observations, large-scale projects and numerical models. Observations of full-scale reservoir stimulations have yielded important results. However, the limited access to the reservoir and limitations in the control on the experimental conditions during deep reservoir stimulations is insufficient to resolve the details of the hydromechanical processes that would enhance process understanding in a way that aids future stimulation design. Small-scale laboratory experiments provide fundamental insights into various processes relevant for enhanced geothermal energy, but suffer from (1) difficulties and uncertainties in upscaling the results to the field scale and (2) relatively homogeneous material and stress conditions that lead to an oversimplistic fracture flow and/or hydraulic fracture propagation behavior that is not representative of a heterogeneous reservoir. Thus, there is a need for intermediate-scale hydraulic stimulation experiments with high experimental control that bridge the various scales and for which access to the target rock mass with a comprehensive monitoring system is possible. The ISC experiment is designed to address open research questions in a naturally fractured and faulted crystalline rock mass at the Grimsel Test Site (Switzerland). Two hydraulic injection phases were executed to enhance the permeability of the rock mass. During the injection phases the rock mass deformation across fractures and within intact rock

A Study of Nonlinear Elasticity Effects on Permeability of Stress Sensitive Shale Rocks Using an Improved Coupled Flow and Geomechanics Model: A Case Study of the Longmaxi Shale in China

Directory of Open Access Journals (Sweden)

Chenji Wei

2018-02-01

Full Text Available Gas transport in shale gas reservoirs is largely affected by rock properties such as permeability. These properties are often sensitive to the in-situ stress state changes. Accurate modeling of shale gas transport in shale reservoir rocks considering the stress sensitive effects on rock petrophysical properties is important for successful shale gas extraction. Nonlinear elasticity in stress sensitive reservoir rocks depicts the nonlinear stress-strain relationship, yet it is not thoroughly studied in previous reservoir modeling works. In this study, an improved coupled flow and geomechanics model that considers nonlinear elasticity is proposed. The model is based on finite element methods, and the nonlinear elasticity in the model is validated with experimental data on shale samples selected from the Longmaxi Formation in Sichuan Basin China. Numerical results indicate that, in stress sensitive shale rocks, nonlinear elasticity affects shale permeability, shale porosity, and distributions of effective stress and pore pressure. Elastic modulus change is dependent on not only in-situ stress state but also stress history path. Without considering nonlinear elasticity, the modeling of shale rock permeability in Longmaxi Formation can overestimate permeability values by 1.6 to 53 times.

INTEGRATED GEOLOGIC-ENGINEERING MODEL FOR REEF AND CARBONATE SHOAL RESERVOIRS ASSOCIATED WITH PALEOHIGHS: UPPER JURASSIC SMACKOVER FORMATION, NORTHEASTERN GULF OF MEXICO

Energy Technology Data Exchange (ETDEWEB)

Ernest A. Mancini

2004-02-25

The University of Alabama, in cooperation with Texas A&M University, McGill University, Longleaf Energy Group, Strago Petroleum Corporation, and Paramount Petroleum Company, has undertaken an integrated, interdisciplinary geoscientific and engineering research project. The project is designed to characterize and model reservoir architecture, pore systems and rock-fluid interactions at the pore to field scale in Upper Jurassic Smackover reef and carbonate shoal reservoirs associated with varying degrees of relief on pre-Mesozoic basement paleohighs in the northeastern Gulf of Mexico. The project effort includes the prediction of fluid flow in carbonate reservoirs through reservoir simulation modeling which utilizes geologic reservoir characterization and modeling and the prediction of carbonate reservoir architecture, heterogeneity and quality through seismic imaging. The primary goal of the project is to increase the profitability, producibility and efficiency of recovery of oil from existing and undiscovered Upper Jurassic fields characterized by reef and carbonate shoals associated with pre-Mesozoic basement paleohighs. Geoscientific reservoir property, geophysical seismic attribute, petrophysical property, and engineering property characterization has shown that reef (thrombolite) and shoal reservoir lithofacies developed on the flanks of high-relief crystalline basement paleohighs (Vocation Field example) and on the crest and flanks of low-relief crystalline basement paleohighs (Appleton Field example). The reef thrombolite lithofacies have higher reservoir quality than the shoal lithofacies due to overall higher permeabilities and greater interconnectivity. Thrombolite dolostone flow units, which are dominated by dolomite intercrystalline and vuggy pores, are characterized by a pore system comprised of a higher percentage of large-sized pores and larger pore throats. Rock-fluid interactions (diagenesis) studies have shown that although the primary control on

Volcanic settings and their reservoir potential: An outcrop analog study on the Miocene Tepoztlán Formation, Central Mexico

Science.gov (United States)

Lenhardt, Nils; Götz, Annette E.

2011-07-01

The reservoir potential of volcanic and associated sedimentary rocks is less documented in regard to groundwater resources, and oil and gas storage compared to siliciclastic and carbonate systems. Outcrop analog studies within a volcanic setting enable to identify spatio-temporal architectural elements and geometric features of different rock units and their petrophysical properties such as porosity and permeability, which are important information for reservoir characterization. Despite the wide distribution of volcanic rocks in Mexico, their reservoir potential has been little studied in the past. In the Valley of Mexico, situated 4000 m above the Neogene volcanic rocks, groundwater is a matter of major importance as more than 20 million people and 42% of the industrial capacity of the Mexican nation depend on it for most of their water supply. Here, we present porosity and permeability data of 108 rock samples representing five different lithofacies types of the Miocene Tepoztlán Formation. This 800 m thick formation mainly consists of pyroclastic rocks, mass flow and fluvial deposits and is part of the southern Transmexican Volcanic Belt, cropping out south of the Valley of Mexico and within the two states of Morelos and Mexico State. Porosities range from 1.4% to 56.7%; average porosity is 24.8%. Generally, permeabilities are low to median (0.2-933.3 mD) with an average permeability of 88.5 mD. The lavas are characterized by the highest porosity values followed by tuffs, conglomerates, sandstones and tuffaceous breccias. On the contrary, the highest permeabilities can be found in the conglomerates, followed by tuffs, tuffaceous breccias, sandstones and lavas. The knowledge of these petrophysical rock properties provides important information on the reservoir potential of volcanic settings to be integrated to 3D subsurface models.

History Matching and Parameter Estimation of Surface Deformation Data for a CO2 Sequestration Field Project Using Ensemble-Based Algorithms

Science.gov (United States)

Tavakoli, Reza; Srinivasan, Sanjay; Wheeler, Mary

2015-04-01

The application of ensemble-based algorithms for history matching reservoir models has been steadily increasing over the past decade. However, the majority of implementations in the reservoir engineering have dealt only with production history matching. During geologic sequestration, the injection of large quantities of CO2 into the subsurface may alter the stress/strain field which in turn can lead to surface uplift or subsidence. Therefore, it is essential to couple multiphase flow and geomechanical response in order to predict and quantify the uncertainty of CO2 plume movement for long-term, large-scale CO2 sequestration projects. In this work, we simulate and estimate the properties of a reservoir that is being used to store CO2 as part of the In Salah Capture and Storage project in Algeria. The CO2 is separated from produced natural gas and is re-injected into downdip aquifer portion of the field from three long horizontal wells. The field observation data includes ground surface deformations (uplift) measured using satellite-based radar (InSAR), injection well locations and CO2 injection rate histories provided by the operators. We implement variations of ensemble Kalman filter and ensemble smoother algorithms for assimilating both injection rate data as well as geomechanical observations (surface uplift) into reservoir model. The preliminary estimation results of horizontal permeability and material properties such as Young Modulus and Poisson Ratio are consistent with available measurements and previous studies in this field. Moreover, the existence of high-permeability channels (fractures) within the reservoir; especially in the regions around the injection wells are confirmed. This estimation results can be used to accurately and efficiently predict and quantify the uncertainty in the movement of CO2 plume.

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).

CO2/ brine substitution experiments at simulated reservoir conditions

Science.gov (United States)

Kummerow, Juliane; Spangenberg, Erik

2015-04-01

Capillary properties of rocks affect the mobility of fluids in a reservoir. Therefore, the understanding of the capillary pressure behaviour is essential to assess the long-term behaviour of CO2 reservoirs. Beyond this, a calibration of the petrophysical properties on water saturation of reservoir rocks at simulated in situ conditions is crucial for a proper interpretation of field monitoring data. We present a set-up, which allows for the combined measurements of capillary pressure, electric resistivity, and elastic wave velocities under controlled reservoir conditions (pconf = 400 bar, ppore = 180 bar, T = 65 ° C) at different brine-CO2 saturations. The capillary properties of the samples are measured using the micropore membrane technique. The sample is jacketed with a Viton tube (thickness = 4 mm) and placed between two current electrode endcaps, which as well contain pore fluid ports and ultrasonic P and S wave transducers. Between the sample and the lower endcap the hydrophilic semi-permeable micro-pore membrane (pore size = 100 nm) is integrated. It is embedded into filter papers to establish a good capillary contact and to protect the highly sensitive membrane against mechanical damage under load. Two high-precision syringe pumps are used to displace a quantified volume of brine by CO2 and determine the corresponding sample saturation. The fluid displacement induces a pressure gradient along the sample, which corresponds to the capillary pressure at a particular sample saturation. It is measured with a differential pressure sensor in the range between 0 - 0.2 MPa. Drainage and imbibition cycles are performed to provide information on the efficiency of capillary trapping and to get a calibration of the petrophysical parameters of the sample.

Evaluation of the potential for reduction in well spacing of the Bakken sand pool, Court Field

Energy Technology Data Exchange (ETDEWEB)

Majcher, M.B.; Estrada, C.A. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Nexen Inc., Calgary, AB (Canada); Archer, J.C. [Nexen Inc., Calgary, AB (Canada)

2005-11-01

For the past 15 years, the Court field has produced hydrocarbons from the Mississippian/Devonian middle Bakken sandstone reservoir. The formation is located in west central Saskatchewan and was deposited in a marine shelf environment and later reworked into tidally influenced sand ridges. Vertical wells and a waterflood recovery scheme have been used to produce heavy crude with an API gravity of 17. A better understanding of the reservoir behaviour is required in order to advance field development and maintain successful waterflood management. Three-dimensional seismic and well logs were used to map the structural complexity of the sand ridge. This study examined the feasibility of using production and seismic data to update and substantiate a simulation model which was used to evaluate downspace potential. Stratigraphic disparities were taken into account as discontinuous interbedded siltstones may be flow barriers that create anisotropy in the permeability zone. Grid orientation was altered to align axially with the permeability trends of the main sand ridge. This study also reviewed an earlier field simulation and generated an updated model. The potential to reduce well spacing was then identified and waterflood optimization of the middle Bakken reservoir was evaluated. It was concluded that the edges of the sand ridge and areas isolated from existing injectors have the greatest potential for infill drilling and additional water injection because of the high sinkhole density. It was noted that drilling edge regions with high oil saturations have a risk of low permeability zones, resulting in low production rates and the possibility of an ineffective waterflood scheme. Therefore, a successful waterflood in the edge zones would require injector-producer pairs in the equivalent sand facies. 4 refs., 36 figs.

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.

Understanding the True Stimulated Reservoir Volume in Shale Reservoirs

KAUST Repository

Hussain, Maaruf

2017-06-06

Successful exploitation of shale reservoirs largely depends on the effectiveness of hydraulic fracturing stimulation program. Favorable results have been attributed to intersection and reactivation of pre-existing fractures by hydraulically-induced fractures that connect the wellbore to a larger fracture surface area within the reservoir rock volume. Thus, accurate estimation of the stimulated reservoir volume (SRV) becomes critical for the reservoir performance simulation and production analysis. Micro-seismic events (MS) have been commonly used as a proxy to map out the SRV geometry, which could be erroneous because not all MS events are related to hydraulic fracture propagation. The case studies discussed here utilized a fully 3-D simulation approach to estimate the SRV. The simulation approach presented in this paper takes into account the real-time changes in the reservoir\\'s geomechanics as a function of fluid pressures. It is consisted of four separate coupled modules: geomechanics, hydrodynamics, a geomechanical joint model for interfacial resolution, and an adaptive re-meshing. Reservoir stress condition, rock mechanical properties, and injected fluid pressure dictate how fracture elements could open or slide. Critical stress intensity factor was used as a fracture criterion governing the generation of new fractures or propagation of existing fractures and their directions. Our simulations were run on a Cray XC-40 HPC system. The studies outcomes proved the approach of using MS data as a proxy for SRV to be significantly flawed. Many of the observed stimulated natural fractures are stress related and very few that are closer to the injection field are connected. The situation is worsened in a highly laminated shale reservoir as the hydraulic fracture propagation is significantly hampered. High contrast in the in-situ stresses related strike-slip developed thereby shortens the extent of SRV. However, far field nature fractures that were not connected to

Non-monotonic permeability variation during colloidal transport: Governing equations and analytical model

Science.gov (United States)

Chequer, L.; Russell, T.; Behr, A.; Genolet, L.; Kowollik, P.; Badalyan, A.; Zeinijahromi, A.; Bedrikovetsky, P.

2018-02-01

Permeability decline associated with the migration of natural reservoir fines impairs the well index of injection and production wells in aquifers and oilfields. In this study, we perform laboratory corefloods using aqueous solutions with different salinities in engineered rocks with different kaolinite content, yielding fines migration and permeability alteration. Unusual permeability growth has been observed at high salinities in rocks with low kaolinite concentrations. This has been attributed to permeability increase during particle detachment and re-attachment of already mobilised fines by electrostatic attraction to the rock in stagnant zones of the porous space. We refine the traditional model for fines migration by adding mathematical expressions for the particle re-attachment rate, particle detachment with delay relative to salinity decrease, and the attached-concentration-dependency of permeability. A one-dimensional flow problem that accounts for those three effects allows for an exact analytical solution. The modified model captures the observed effect of permeability increase at high water salinities in rocks with low kaolinite concentrations. The developed model matches the coreflooding data with high accuracy, and the obtained model coefficients vary within their usual intervals.

Implications of heterogeneous fracture distribution on reservoir quality; an analogue from the Torridon Group sandstone, Moine Thrust Belt, NW Scotland

Science.gov (United States)

Watkins, Hannah; Healy, David; Bond, Clare E.; Butler, Robert W. H.

2018-03-01

Understanding fracture network variation is fundamental in characterising fractured reservoirs. Simple relationships between fractures, stress and strain are commonly assumed in fold-thrust structures, inferring relatively homogeneous fracture patterns. In reality fractures are more complex, commonly appearing as heterogeneous networks at outcrop. We use the Achnashellach Culmination (NW Scotland) as an outcrop analogue to a folded tight sandstone reservoir in a thrust belt. We present fracture data is collected from four fold-thrust structures to determine how fracture connectivity, orientation, permeability anisotropy and fill vary at different structural positions. We use a 3D model of the field area, constructed using field observations and bedding data, and geomechanically restored using Move software, to determine how factors such as fold curvature and strain influence fracture variation. Fracture patterns in the Torridon Group are consistent and predictable in high strain forelimbs, however in low strain backlimbs fracture patterns are inconsistent. Heterogeneities in fracture connectivity and orientation in low strain regions do not correspond to fluctuations in strain or fold curvature. We infer that where strain is low, other factors such as lithology have a greater control on fracture formation. Despite unpredictable fracture attributes in low strain regions, fractured reservoir quality would be highest here because fractures in high strain forelimbs are infilled with quartz. Heterogeneities in fracture attribute data on fold backlimbs mean that fractured reservoir quality and reservoir potential is difficult to predict.

Application of advanced reservoir characterization, simulation and production optimization strategies to maximize recovery in slope and basin clastic reservoirs, West Texas (Delaware Basin). Annual report

Energy Technology Data Exchange (ETDEWEB)

Dutton, S.P.; Asquith, G.B.; Barton, M.D.; Cole, A.G.; Gogas, J.; Malik, M.A.; Clift, S.J.; Guzman, J.I.

1997-11-01

The objective of this project is to demonstrate that detailed reservoir characterization of slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost-effective way to recover a higher percentage of the original oil in place through strategic placement of infill wells and geologically based field development. This project involves reservoir characterization of two Late Permian slope and basin clastic reservoirs in the Delaware Basin, West Texas, followed by a field demonstration in one of the fields. The fields being investigated are Geraldine Ford and Ford West fields in Reeves and Culberson Counties, Texas. Project objectives are divided into two major phases, reservoir characterization and implementation. The objectives of the reservoir characterization phase of the project were to provide a detailed understanding of the architecture and heterogeneity of the two fields, the Ford Geraldine unit and Ford West field. Reservoir characterization utilized 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once reservoir characterized was completed, a pilot area of approximately 1 mi{sup 2} at the northern end of the Ford Geraldine unit was chosen for reservoir simulation. This report summarizes the results of the second year of reservoir characterization.

An Integrated Study of the Grayburg/San Andres Reservoir, Foster and South Cowden Fields, Ector County, Texas, Class II

Energy Technology Data Exchange (ETDEWEB)

Trentham, Robert C.; Weinbrandt, Richard; Robinson, William C.; Widner, Kevin

2001-05-03

The objectives of the project were to: (1) Thoroughly understand the 60-year history of the field. (2) Develop a reservoir description using geology and 3D seismic. (3) Isolate the upper Grayburg in wells producing from multiple intervals to stop cross flow. (4) Re-align and optimize the upper Grayburg waterflood. (5) Determine well condition, identify re-frac candidates, evaluate the effectiveness of well work and obtain bottom hole pressure data for simulation utilizing pressure transient testing field wide. (6) Quantitatively integrate all the data to guide the field operations, including identification of new well locations utilizing reservoir simulation.

Transformable ferroelectric control of dynamic magnetic permeability

Science.gov (United States)

Jiang, Changjun; Jia, Chenglong; Wang, Fenglong; Zhou, Cai; Xue, Desheng

2018-02-01

Magnetic permeability, which measures the response of a material to an applied magnetic field, is crucial to the performance of magnetic devices and related technologies. Its dynamic value is usually a complex number with real and imaginary parts that describe, respectively, how much magnetic power can be stored and lost in the material. Control of permeability is therefore closely related to energy redistribution within a magnetic system or energy exchange between magnetic and other degrees of freedom via certain spin-dependent interactions. To avoid a high power consumption, direct manipulation of the permeability with an electric field through magnetoelectric coupling leads to high efficiency and simple operation, but remains a big challenge in both the fundamental physics and material science. Here we report unambiguous evidence of ferroelectric control of dynamic magnetic permeability in a Co /Pb (Mg1/3Nb2/3) 0.7Ti0.3O3 (Co/PMN-PT) heterostructure, in which the ferroelectric PMN-PT acts as an energy source for the ferromagnetic Co film via an interfacial linear magnetoelectric interaction. The electric field tuning of the magnitude and line shape of the permeability offers a highly localized means of controlling magnetization with ultralow power consumption. Additionally, the emergence of negative permeability promises a new way of realizing functional nanoscale metamaterials with adjustable refraction index.

Reservoir Characterization, Production Characteristics, and Research Needs for Fluvial/Alluvial Reservoirs in the United States

Energy Technology Data Exchange (ETDEWEB)

Cole, E.L.; Fowler, M.L.; Jackson, S.R.; Madden, M.P.; Raw-Schatzinger, V.; Salamy, S.P.; Sarathi, P.; Young, M.A.

1999-04-28

The Department of Energy's (DOE's) Oil Recovery Field Demonstration Program was initiated in 1992 to maximize the economically and environmentally sound recovery of oil from known domestic reservoirs and to preserve access to this resource. Cost-shared field demonstration projects are being initiated in geology defined reservoir classes which have been prioritized by their potential for incremental recovery and their risk of abandonment. This document defines the characteristics of the fifth geological reservoir class in the series, fluvial/alluvial reservoirs. The reservoirs of Class 5 include deposits of alluvial fans, braided streams, and meandering streams. Deposit morphologies vary as a complex function of climate and tectonics and are characterized by a high degree of heterogeneity to fluid flow as a result of extreme variations in water energy as the deposits formed.

Recovery by imbibition from the lower Tamaulipas reservoir section A, Tamaulipas-Constituciones field

Energy Technology Data Exchange (ETDEWEB)

Gonzalez, O D; Teyssier S, J

1967-08-01

The Tamaulipas-Constituciones Field is situated about 27 km from the city and port of Tampico, Mex., and is a part of the N. district, of the N. Development Zone of Petroleos Mexicanos. This article describes a method designed to calculate the recovery of oil by means of the application of a secondary recovery process based on the phenomenon of imbibition. The flow in the reservoir follows a system of fractures which are interconnected both in series, parallel, and randomly distributed. A more adequate method of development was determined than that which was enforced when the area wells started their initial production. Applying this method, 2 programs were developed; the first for an operation pressure of 125 kg per sq cm and the second for an operation pressure of 100 kg per cm. The production history is graphically represented. The characteristics of the reservoir are described, including the rock properties and the reservoir fluids. Complete information is furnished on the entire operation by means of tabular data. (15 refs.)

Negative permeability from random particle composites

Energy Technology Data Exchange (ETDEWEB)

Hussain, Shahid, E-mail: shussain2@qinetiq.com

2017-04-15

Artificial media, such as those composed of periodically-spaced wires for negative permittivity and split ring resonators for negative permeability have been extensively investigated for negative refractive index (NRI) applications (Smith et al., 2004; Pendry et al., 1999) [1,2]. This paper presents an alternative method for producing negative permeability: granular (or particulate) composites incorporating magnetic fillers. Artificial media, such as split-ring resonators, are designed to produce a magnetic resonance feature, which results in negative permeability over a narrow frequency range about the resonance frequency. The position of the feature is dependent upon the size of the inclusion. The material in this case is anisotropic, such that the feature is only observable when the materials are orientated in a specific direction relative to the applied field. A similar resonance can be generated in magnetic granular (particulate) materials: ferromagnetic resonance from the natural spin resonance of particles. Although the theoretical resonance profiles in granular composites shows the permeability dipping to negative values, this is rarely observed experimentally due to resonance damping effects. Results are presented for iron in spherical form and in flake form, dispersed in insulating host matrices. The two particle shapes show different permeability performance, with the magnetic flakes producing a negative contribution. This is attributed to the stronger coupling with the magnetic field resulting from the high aspect ratio of the flakes. The accompanying ferromagnetic resonance is strong enough to overcome the effects of damping and produce negative permeability. The size of random particle composites is not dictated by the wavelength of the applied field, so the materials are potentially much thinner than other, more traditional artificial composites at microwave frequencies. - Highlights: • Negative permeability from random particle composites is

A non-erasable magnetic memory based on the magnetic permeability

International Nuclear Information System (INIS)

Petrie, J.R.; Wieland, K.A.; Burke, R.A.; Newburgh, G.A.; Burnette, J.E.; Fischer, G.A.; Edelstein, A.S.

2014-01-01

A non-erasable memory based on using differences in the magnetic permeability is demonstrated. The method can potentially store information indefinitely. Initially the high permeability bits were 10–50 μm wide lines of sputtered permalloy (Ni 81 Fe 19 ) on a glass substrate. In a second writing technique a continuous film of amorphous, high permeability ferromagnetic Metglas (Fe 78 Si 13 B 9 ) was sputtered onto a similar glass substrate. Low permeability, crystalline 50 μm wide lines were then written in the film by laser heating. Both types of written media were read by applying an external probe field that is locally modified by the permeability of each bit. The modifications in the probe field were read by a nearby set of 10 micron wide magnetic tunnel junctions with a signal-to-noise ratio of up to 45 dB. This large response to changes in bit permeability is not altered after the media has been exposed to a 6400 Oe field. While being immediately applicable for data archiving and secure information storage, higher densities are possible with smaller read and write heads. - Highlights: • We demonstrate a non-erasable memory based on changes in the magnetic permeability. • Large change in permeability occur when Metglas changes from amorphous to crystalline. • Micron size regions of Metglas can be crystallized using a laser. • Permeability changes read by observing deviations of a probe field with an MTJ

Pressurization Risk Assessment of CO2 Reservoirs Utilizing Design of Experiments and Response Surface Methods

Science.gov (United States)

Guyant, E.; Han, W. S.; Kim, K. Y.; Park, E.; Han, K.

2015-12-01

Monitoring of pressure buildup can provide explicit information on reservoir integrity and is an appealing tool, however pressure variation is dependent on a variety of factors causing high uncertainty in pressure predictions. This work evaluated pressurization of a reservoir system in the presence of leakage pathways as well as exploring the effects of compartmentalization of the reservoir utilizing design of experiments (Definitive Screening, Box Behnken, Central Composite, and Latin Hypercube designs) and response surface methods. Two models were developed, 1) an idealized injection scenario in order to evaluate the performance of multiple designs, and 2) a complex injection scenario implementing the best performing design to investigate pressurization of the reservoir system. A holistic evaluation of scenario 1, determined that the Central Composite design would be used for the complex injection scenario. The complex scenario evaluated 5 risk factors: reservoir, seal, leakage pathway and fault permeabilities, and horizontal position of the pathway. A total of 60 response surface models (RSM) were developed for the complex scenario with an average R2 of 0.95 and a NRMSE of 0.067. Sensitivity to the input factors was dynamic through space and time; at the earliest time (0.05 years) the reservoir permeability was dominant, and for later times (>0.5 years) the fault permeability became dominant for all locations. The RSM's were then used to conduct a Monte Carlo Analysis to further analyze pressurization risks, identifying the P10, P50, P90 values. This identified the in zone (lower) P90 values as 2.16, 1.77, and 1.53 MPa and above zone values of 1.35, 1.23, 1.09 MPa for monitoring locations 1, 2, and 3, respectively. In summary, the design of experiments and response surface methods allowed for an efficient sensitivity and uncertainty analysis to be conducted permitting a complete evaluation of the pressurization across the entire parameter space.

Enhancement of the sweep efficiency of waterflooding operations by the in-situ microbial population of petroleum reservoirs

Energy Technology Data Exchange (ETDEWEB)

Brown, L.R.; Vadie, A.A.; Stephens, J.O.; Azadpour, A.

1995-12-31

Live cores were obtained from five reservoirs using special precautions to prevent contamination by exogenous microorganisms and minimize exposure to oxygen. The depths from which the cores were obtained ranged from 2,705 ft to 6,568 ft. Core plugs were cut radially from live cores, encased in heat-shrink plastic tubes, placed in core holders, and fitted with inlets and outlets. Nutrient additions stimulated the in-situ microbial population to increase, dissolve stratal material, produce gases, and release oil. Reduction in flow through the core plugs was observed in some cases, while in other cases flow was increased, probably due to the dissolution of carbonates in the formation. A field demonstration of the ability of the in-situ microbial population to increase oil recovery by blocking the more permeable zones of the reservoir is currently underway. This demonstration is being conducted in the North Blowhorn Creek Unit situated in Lamar County, Alabama. Live cores were obtained from a newly drilled well in the field and tested as described above. The field project involves four test patterns each including one injector, four to five producers, and a comparable control injector with its four to five producers. Nutrient injection in the field began November 1994.

Practices and prospect of petroleum engineering technologies in ultra-deep sour gas reservoirs, Yuanba Gasfield, Sichuan Basin

Directory of Open Access Journals (Sweden)

Jin Xu

2016-12-01

Full Text Available Located in the Sichuan Basin, the Yuanba Gasfield is the deepest marine sour gas field among those developed in China so far. Its biohermal gas reservoir of the Upper Permian Changxing Fm is characterized by ultra depth, high content of hydrogen sulfide, medium–low porosity and permeability, and small reservoir thickness. Economic evaluation on it shows that horizontal well drilling is the only way to develop this gas reservoir efficiently and to reduce the total development investment. At present, the petroleum engineering technology for this type of ultra-deep sour gas reservoir is less applied in the world, so an ultra-deep horizontal well is subject to a series of petroleum engineering technology difficulties, such as safe and fast well drilling and completion, mud logging, well logging, downhole operation, safety and environmental protection. Based on the successful development experience of the Puguang Gasfield, therefore, Sinopec Southwest Petroleum Engineering Co., Ltd. took the advantage of integrated engineering geology method to carry out specific technical research and perform practice diligently for 7 years. As a result, 18 key items of technologies for ultra-deep sour gas reservoirs were developed, including horizontal-well drilling speed increasing technology, horizontal-well mud logging and well logging technology, downhole operation technology, and safety and environmental protection technology. These technologies were applied in 40 wells during the first and second phases of productivity construction of the Yuanba Gasfield. All the 40 wells have been built into commercial gas wells, and the productivity construction goal of 3.4 billion m3 purified gas has also been achieved. These petroleum engineering technologies for ultra-deep sour gas fields play a reference role in exploring and developing similar gas reservoirs at home and abroad.

Permeability in Rotliegend gas sandstones to gas and brine as predicted from NMR, mercury injection and image analysis

DEFF Research Database (Denmark)

Rosenbrand, Esther; Fabricius, Ida Lykke; Fisher, Quentin

2015-01-01

Permeability characterisation of low permeability, clay-rich gas sandstones is part of production forecasting and reservoir management. The physically based Kozeny (1927) equation linking permeability with porosity and pore size is derived for a porous medium with a homogeneous pore size, whereas...... the pore sizes in tight sandstones can range from nm to μm. Nuclear magnetic resonance (NMR) transverse relaxation was used to estimate a pore size distribution for 63 samples of Rotliegend sandstone. The surface relaxation parameter required to relate NMR to pore size is estimated by combination of NMR...

Experimental observation of permeability changes in dolomite at CO2 sequestration conditions.

Science.gov (United States)

Tutolo, Benjamin M; Luhmann, Andrew J; Kong, Xiang-Zhao; Saar, Martin O; Seyfried, William E

2014-02-18

Injection of cool CO2 into geothermally warm carbonate reservoirs for storage or geothermal energy production may lower near-well temperature and lead to mass transfer along flow paths leading away from the well. To investigate this process, a dolomite core was subjected to a 650 h, high pressure, CO2 saturated, flow-through experiment. Permeability increased from 10(-15.9) to 10(-15.2) m(2) over the initial 216 h at 21 °C, decreased to 10(-16.2) m(2) over 289 h at 50 °C, largely due to thermally driven CO2 exsolution, and reached a final value of 10(-16.4) m(2) after 145 h at 100 °C due to continued exsolution and the onset of dolomite precipitation. Theoretical calculations show that CO2 exsolution results in a maximum pore space CO2 saturation of 0.5, and steady state relative permeabilities of CO2 and water on the order of 0.0065 and 0.1, respectively. Post-experiment imagery reveals matrix dissolution at low temperatures, and subsequent filling-in of flow passages at elevated temperature. Geochemical calculations indicate that reservoir fluids subjected to a thermal gradient may exsolve and precipitate up to 200 cm(3) CO2 and 1.5 cm(3) dolomite per kg of water, respectively, resulting in substantial porosity and permeability redistribution.

Porous media experience applicable to field evaluation for compressed air energy storage

Energy Technology Data Exchange (ETDEWEB)

Allen, R.D.; Gutknecht, P.J.

1980-06-01

A survey is presented of porous media field experience that may aid in the development of a compressed air energy storage field demonstration. Work done at PNL and experience of other groups and related industries is reviewed. An overall view of porous media experience in the underground storage of fluids is presented. CAES experience consists of site evaluation and selection processes used by groups in California, Kansas, and Indiana. Reservoir design and field evaluation of example sites are reported. The studies raised questions about compatibility with depleted oil and gas reservoirs, storage space rights, and compressed air regulations. Related experience embraces technologies of natural gas, thermal energy, and geothermal and hydrogen storage. Natural gas storage technology lends the most toward compressed air storage development, keeping in mind the respective differences between stored fluids, physical conditions, and cycling frequencies. Both fluids are injected under pressure into an aquifer to form a storage bubble confined between a suitable caprock structure and partially displaced ground water. State-of-the-art information is summarized as the necessary foundation material for field planning. Preliminary design criteria are given as recommendations for basic reservoir characteristics. These include geometric dimensions and storage matrix properties such as permeability. Suggested ranges are given for injection air temperature and reservoir pressure. The second step in developmental research is numerical modeling. Results have aided preliminary design by analyzing injection effects upon reservoir pressure, temperature and humidity profiles. Results are reported from laboratory experiments on candidate sandstones and caprocks. Conclusions are drawn, but further verification must be done in the field.

Electromagnetic Monitoring of Hydraulic Fracturing: Relationship to Permeability, Seismicity, and Stress

Science.gov (United States)

Thiel, Stephan

2017-09-01

Hydraulic fracking is a geoengineering application designed to enhance subsurface permeability to maximize fluid and gas flow. Fracking is commonly used in enhanced geothermal systems (EGS), tight shale gas, and coal seam gas (CSG) plays and in CO_2 storage scenarios. Common monitoring methods include microseismics and mapping small earthquakes with great resolution associated with fracture opening at reservoir depth. Recently, electromagnetic (EM) methods have been employed in the field to provide an alternative way of direct detection of fluids as they are pumped in the ground. Surface magnetotelluric (MT) measurements across EGS show subtle yet detectable changes during fracking derived from time-lapse MT deployments. Changes are directional and are predominantly aligned with current stress field, dictating preferential fracture orientation, supported by microseismic monitoring of frack-related earthquakes. Modeling studies prior to the injection are crucial for survey design and feasibility of monitoring fracks. In particular, knowledge of sediment thickness plays a fundamental role in resolving subtle changes. Numerical forward modeling studies clearly favor some form of downhole measurement to enhance sensitivity; however, these have yet to be conclusively demonstrated in the field. Nevertheless, real surface-based monitoring examples do not necessarily replicate the expected magnitude of change derived from forward modeling and are larger than expected in some cases from EGS and CSG systems. It appears the injected fluid volume alone cannot account for the surface change in resistivity, but connectedness of pore space is also significantly enhanced and nonlinear. Recent numerical studies emphasize the importance of percolation threshold of the fracture network on both electrical resistivity and permeability, which may play an important role in accounting for temporal changes in surface EM measurements during hydraulic fracking.

Oxygen isotope geochemistry of The Geysers reservoir rocks, California

Energy Technology Data Exchange (ETDEWEB)

Gunderson, Richard P.; Moore, Joseph N.

1994-01-20

Whole-rock oxygen isotopic compositions of Late Mesozoic graywacke, the dominant host rock at The Geysers, record evidence of a large liquid-dominated hydrothermal system that extended beyond the limits of the present steam reservoir. The graywackes show vertical and lateral isotopic variations that resulted from gradients in temperature, permeability, and fluid composition during this early liquid-dominated system. All of these effects are interpreted to have resulted from the emplacement of the granitic "felsite" intrusion 1-2 million years ago. The {delta}{sup 18}O values of the graywacke are strongly zoned around a northwest-southeast trending low located near the center of and similar in shape to the present steam system. Vertical isotopic gradients show a close relationship to the felsite intrusion. The {delta}{sup 18}O values of the graywacke decrease from approximately 15 per mil near the surface to 4-7 per mil 300 to 600 m above the intrusive contact. The {delta}{sup 18}O values then increase downward to 8-10 per mil at the felsite contact, thereafter remaining nearly constant within the intrusion itself. The large downward decrease in {delta}{sup 18}O values are interpreted to be controlled by variations in temperature during the intrusive event, ranging from 150{degree}C near the surface to about 425{degree}C near the intrusive contact. The upswing in {delta}{sup 18}O values near the intrusive contact appears to have been caused by lower rock permeability and/or heavier fluid isotopic composition there. Lateral variations in the isotopic distributions suggests that the effects of temperature were further modified by variations in rock permeability and/or fluid-isotopic composition. Time-integrated water:rock ratios are thought to have been highest within the central isotopic low where the greatest isotopic depletions are observed. We suggest that this region of the field was an area of high permeability within the main upflow zone of the liquid

Constructing reservoir-scale 3D geomechanical FE-models. A refined workflow for model generation and calculation

Energy Technology Data Exchange (ETDEWEB)

Fischer, K.; Henk, A. [Technische Univ. Darmstadt (Germany). Inst. fuer Angewandte Geowissenschaften

2013-08-01

The tectonic stress field strongly affects the optimal exploitation of conventional and unconventional hydrocarbon reservoirs. Amongst others, wellbore stability, orientation of hydraulically induced fractures and - particularly in fractured reservoirs - permeability anisotropies depend on the magnitudes and orientations of the recent stresses. Geomechanical reservoir models can provide unique insights into the tectonic stress field revealing the local perturbations resulting from faults and lithological changes. In order to provide robust predictions, such numerical models are based on the finite element (FE) method and account for the complexities of real reservoirs with respect to subsurface geometry, inhomogeneous material distribution and nonlinear rock mechanical behavior. We present a refined workflow for geomechanical reservoir modeling which allows for an easier set-up of the model geometry, high resolution submodels and faster calculation times due to element savings in the load frame. Transferring the reservoir geometry from the geological subsurface model, e.g., a Petrel {sup registered} project, to the FE model represents a special challenge as the faults are discontinuities in the numerical model and no direct interface exists between the two software packages used. Point clouds displaying faults and lithostratigraphic horizons can be used for geometry transfer but this labor-intensive approach is not feasible for complex field-scale models with numerous faults. Instead, so-called Coon's patches based on horizon lines, i.e. the intersection lines between horizons and faults, are well suited to re-generate the various surfaces in the FE software while maintaining their topology. High-resolution submodels of individual fault blocks can be incorporated into the field-scale model. This allows to consider both a locally refined mechanical stratigraphy and the impact of the large-scale fault pattern. A pressure load on top of the model represents the

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

Gypsy Field Project in Reservoir Characterization

International Nuclear Information System (INIS)

John P. Castagna; William J. Lamb; Carlos Moreno; Roger Young; Lynn Soreghan

2006-01-01

The objective of the Gypsy Project was to properly calculate seismic attributes and integrate these into a reservoir characterization project. Significant progress was made on the project in four areas. (1) Attenuation: In order for seismic inversion for rock properties or calculation of seismic attributes used to estimate rock properties to be performed validly, it is necessary to deal with seismic data that has had true amplitude and frequency content restored to account for earth filtering effects that are generally not included in seismic reservoir characterization methodologies. This requires the accurate measurement of seismic attenuation, something that is rarely achieved in practice. It is hoped that such measurements may also provide additional independent seismic attributes for use in reservoir characterization studies. In 2000, we were concerned with the ground truthing of attenuation measurements in the vicinity of wells. Our approach to the problem is one of extracting as time varying wavelet and relating temporal variations in the wavelet to an attenuation model of the earth. This method has the advantage of correcting for temporal variations in the reflectivity spectrum of the earth which confound the spectral ratio methodology which is the most commonly applied means of measuring attenuation from surface seismic data. Part I of the report describes our efforts in seismic attenuation as applied to the Gypsy data. (2) Optimal Attributes: A bewildering array of seismic attributes is available to the reservoir geoscientist to try to establish correlations to rock properties. Ultimately, the use of such a large number of degrees of freedom in the search for correlations with limited well control leads to common misapplication of statistically insignificant results which yields invalid predictions. Cross-validation against unused wells can be used to recognize such problems, but does not offer a solution to the question of which attributes should be used

Estimating the Permeability of Carbonate Rocks from the Fractal Properties of Moldic Pores using the Kozeny-Carman Equation

Directory of Open Access Journals (Sweden)

Adewale Amosu

2018-02-01

Full Text Available Reservoir modeling of carbonate rocks requires a proper understanding of the pore space distribution and its relationship to permeability. Using a pigeonhole fractal model we characterize the fractal geometry of moldic pore spaces and extract the fractal dimension. We apply the Kozeny-Carman equation and equations relating the tortuosity and the porosity to the fractal dimension to derive an empirical relationship between permeability and porosity.

The Effect of Bacteria Penetration on Chalk Permeability

DEFF Research Database (Denmark)

Halim, Amalia Yunita; Shapiro, Alexander; Nielsen, Sidsel Marie

number of B. licheniformis was detected on the effluent compared with P. putida. However, in the experiment with B. licheniformis mainly spores were detected in the effluent. The core permeability decreased rapidly during injection of bacteria and a starvation period of 12 days did not allow......Bacteria selective plugging is one of the mechanisms through which microorganisms can be applied for enhanced oil recovery. Bacteria can plug the water-bearing zones of a reservoir, thus altering the flow paths and improving sweep efficiency. It is known that the bacteria can penetrate deeply...... into reservoirs, however, a complete understanding of the penetration behavior of bacteria is lacking, especially in chalk formations where the pore throat sizes are almost comparable with the sizes of bacteria vegetative cells. This study investigates the penetration of bacteria into chalk. Two bacteria types...

Permeable pavement study (Edison)

Data.gov (United States)