Determination of residual oil saturation from time-lapse pulsed neutron capture logs in a large sandstone reservoir

International Nuclear Information System (INIS)

Syed, E.V.; Salaita, G.N.; McCaffery, F.G.

1991-01-01

Cased hole logging with pulsed neutron tools finds extensive use for identifying zones of water breakthrough and monitoring oil-water contacts in oil reservoirs being depleted by waterflooding or natural water drive. Results of such surveys then find direct use for planning recompletions and water shutoff treatments. Pulsed neutron capture (PNC) logs are useful for estimating water saturation changes behind casing in the presence of a constant, high-salinity environment. PNC log surveys run at different times, i.e., in a time-lapse mode, are particularly amenable to quantitative analysis. The combined use of the original open hole and PNC time-lapse log information can then provide information on remaining or residual oil saturations in a reservoir. This paper reports analyses of historical pulsed neutron capture log data to assess residual oil saturation in naturally water-swept zones for selected wells from a large sandstone reservoir in the Middle East. Quantitative determination of oil saturations was aided by PNC log information obtained from a series of tests conducted in a new well in the same field

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

KAUST Repository

Katterbauer, Klemens

2014-01-01

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

Depletion policies for oil-exporting developing economies

Energy Technology Data Exchange (ETDEWEB)

Stournaras, Y A

1984-01-01

The fact that most oil-exporting countries are developing economies has important implications for oil supply which have not been properly taken into account in the literature on exhaustible resource depletion. The way in which depletion policies are affected by trade uncertainty, given the high degree of the major oil exporters' 'dependence' on crude oil revenues, by investment time lags which delay the exploitation of (some of) these countries' comparative advantage in a petroleum based development, and by ideological objections to the ideal of a rentier society and to foreign capital are examined.

Potential hazards of compressed air energy storage in depleted natural gas reservoirs.

Energy Technology Data Exchange (ETDEWEB)

Cooper, Paul W.; Grubelich, Mark Charles; Bauer, Stephen J.

2011-09-01

This report is a preliminary assessment of the ignition and explosion potential in a depleted hydrocarbon reservoir from air cycling associated with compressed air energy storage (CAES) in geologic media. The study identifies issues associated with this phenomenon as well as possible mitigating measures that should be considered. Compressed air energy storage (CAES) in geologic media has been proposed to help supplement renewable energy sources (e.g., wind and solar) by providing a means to store energy when excess energy is available, and to provide an energy source during non-productive or low productivity renewable energy time periods. Presently, salt caverns represent the only proven underground storage used for CAES. Depleted natural gas reservoirs represent another potential underground storage vessel for CAES because they have demonstrated their container function and may have the requisite porosity and permeability; however reservoirs have yet to be demonstrated as a functional/operational storage media for compressed air. Specifically, air introduced into a depleted natural gas reservoir presents a situation where an ignition and explosion potential may exist. This report presents the results of an initial study identifying issues associated with this phenomena as well as possible mitigating measures that should be considered.

Enhanced heavy oil recovery on depleted long core system by CH{sub 4} and CO{sub 2}

Energy Technology Data Exchange (ETDEWEB)

Shi, R.; Kantzas, A. [Calgary Univ., AB (Canada). Tomographic Imaging and Porous Media Laboratory

2008-10-15

As demand for energy continues to increase and production of conventional oil declines, additional development of heavy oil and bitumen recovery processes and technologies is required in order to meet future energy demands. However, if productions are to be achieved economically, heavy oil viscosity must be reduced. Two methods are normally used to reduce heavy oil viscosity, notably thermal processes such as steam assisted gravity drainage and solvent processes. This paper described a laboratory study of potential post-cold production strategies for heavy oil reservoirs. Methane and carbon dioxide were injected in two depleted long cores. The purpose of the study was to improve understanding of the heavy oil solution gas drive mechanism and to assess methane and carbon dioxide recharging as a potential recovery method for heavy oil reservoirs. It also sought to establish a baseline for comparison against one another. The paper described the methodology and provided a summary of previous production history. It was concluded that the saturation and production time difference between the glass beads core and the sandpack core indicate the permeability difference between the two cores. 12 refs., 2 tabs., 14 figs.

DEPLETED HYDROCARBON RESERVOIRS AND CO2 INJECTION WELLS –CO2 LEAKAGE ASSESSMENT

Directory of Open Access Journals (Sweden)

Nediljka Gaurina-Međimurec

2017-03-01

Full Text Available Migration risk assessment of the injected CO2 is one of the fi rst and indispensable steps in determining locations for the implementation of projects for carbon dioxide permanent disposal in depleted hydrocarbon reservoirs. Within the phase of potential storage characterization and assessment, it is necessary to conduct a quantitative risk assessment, based on dynamic reservoir models that predict the behaviour of the injected CO2, which requires good knowledge of the reservoir conditions. A preliminary risk assessment proposed in this paper can be used to identify risks of CO2 leakage from the injection zone and through wells by quantifying hazard probability (likelihood and severity, in order to establish a risk-mitigation plan and to engage prevention programs. Here, the proposed risk assessment for the injection well is based on a quantitative risk matrix. The proposed assessment for the injection zone is based on methodology used to determine a reservoir probability in exploration and development of oil and gas (Probability of Success, abbr. POS, and modifi ed by taking into account hazards that may lead to CO2 leakage through the cap rock in the atmosphere or groundwater. Such an assessment can eliminate locations that do not meet the basic criteria in regard to short-term and long-term safety and the integrity of the site

Depletion of compounds from thin oil films in seawater

International Nuclear Information System (INIS)

Brakstad, O.G.; Faksness, L.G.; Melbye, A.G.

2002-01-01

When oil is spilled on water, the oil compounds distribute between droplets and water-soluble phases in the water column. Some small organic acids, phenols, BTEX, and aromatic compounds will dissolve completely, but larger polycyclic aromatic hydrocarbons (PAH) and alkanes will remain in the droplet fraction. The biodegradation of droplets occurs at the oil-water interface. A method for immobilizing the oil films onto hydrophobic surfaces was developed in order to obtain a stable oil surface during the biodegradation period. A test system was also established to determine the depletion of oil compounds from the oil phase, including both abiotic and biotic processes. Three North Sea oils were used in the study. Two were paraffinic oils rich in n-alkanes and aromatic compounds, and one was asphalthenic which was richer in branched alkanes and PAH. The biodegradation period was 2 months at 13 degrees C. Samples from the water and thin film on the fabric was analyzed for carbon 10 and carbon 36 by gas chromatography-flame ionization detection. Semi-volatile organic compounds were analyzed using gas chromatography-mass spectrometry. Results indicated that the depletion process for alkanes was completely caused by biodegradation, while aromatic compounds were depleted by abiotic dissolution as well as by biodegradation. The system has potential for determining oil depletion processes under controlled surface-to-volume conditions, such as thin oil films and dispersed oil droplets. In addition, the system can be used to determine the depletion process in flow-through systems. 13 refs., 3 tabs., 9 figs

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

Directory of Open Access Journals (Sweden)

Hu Jia

2017-06-01

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

The impact of pressure-dependent interfacial tension and buoyancy forces upon pressure depletion in virgin hydrocarbon reservoirs

Energy Technology Data Exchange (ETDEWEB)

McDougall, S.R.; Mackay, E.J. [Heriot-Watt University, Edinburgh (United Kingdom). Dept. of Petroleum Engineering

1998-07-01

This paper describes a combined experimental and theoretical study of the microscopic pore-scale physics characterizing gas and liquid production from hydrocarbon reservoirs during pressure depletion. The primary focus of the study was to examine the complex interactions between interfacial tension and buoyancy forces during gas evolution within a porous medium containing oil, water and gas. A specialized 2-dimensional glass micromodel, capable of operating at pressure in excess of 35 MPa was used to visualize the physical mechanisms governing such microscopic processes. In addition, a 3-dimensional, 3-phase numerical pore-scale simulator was developed that can be used to examine gas evolution over a range of different lengthscales and for a wide range of fluid and rock properties. The model incorporates all of the important physics observed in associated laboratory micromodel experiments, including: embryonic nucleation, supersaturation effects, multiphase diffusion, bubble growth-migration-fragmentation, and three-phase spreading coefficients. The precise pore-scale mechanisms governing gas evolution were found to be far more subtle than earlier models would suggest because of the large variation of gas/oil interfacial tension with pressure. This has a profound effect upon the migration of gas structures during depletion and, in models pertaining to reservoir rock, the process of gas migration is consequently much slower than previously thought. This is the first time that such a phenomena has been modelled at the pore-scale and the implications for production forecasting are thought to be significant. (author)

Design of a lube oil reservoir by using flow calculations

Energy Technology Data Exchange (ETDEWEB)

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

1998-12-31

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

Design of a lube oil reservoir by using flow calculations

Energy Technology Data Exchange (ETDEWEB)

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

1997-12-31

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

Oil Reservoir Production Optimization using Optimal Control

DEFF Research Database (Denmark)

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

2011-01-01

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

CO2 storage in depleted gas reservoirs: A study on the effect of residual gas saturation

Directory of Open Access Journals (Sweden)

Arshad Raza

2018-03-01

Full Text Available Depleted gas reservoirs are recognized as the most promising candidate for carbon dioxide storage. Primary gas production followed by injection of carbon dioxide after depletion is the strategy adopted for secondary gas recovery and storage practices. This strategy, however, depends on the injection strategy, reservoir characteristics and operational parameters. There have been many studies to-date discussing critical factors influencing the storage performance in depleted gas reservoirs while little attention was given to the effect of residual gas. In this paper, an attempt was made to highlight the importance of residual gas on the capacity, injectivity, reservoir pressurization, and trapping mechanisms of storage sites through the use of numerical simulation. The results obtained indicated that the storage performance is proportionally linked to the amount of residual gas in the medium and reservoirs with low residual fluids are a better choice for storage purposes. Therefore, it would be wise to perform the secondary recovery before storage in order to have the least amount of residual gas in the medium. Although the results of this study are useful to screen depleted gas reservoirs for the storage purpose, more studies are required to confirm the finding presented in this paper.

Opportunities to improve oil productivity in unstructured deltaic reservoirs

Energy Technology Data Exchange (ETDEWEB)

1991-01-01

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

Characterization of oil and gas reservoir heterogeneity

Energy Technology Data Exchange (ETDEWEB)

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

1992-10-01

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

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.

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

KAUST Repository

Katterbauer, Klemens; Hoteit, Ibrahim

2014-01-01

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

Liquid oil production from shale gas condensate reservoirs

Science.gov (United States)

Sheng, James J.

2018-04-03

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

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

Carbon sequestration in depleted oil shale deposits

Science.gov (United States)

Burnham, Alan K; Carroll, Susan A

2014-12-02

A method and apparatus are described for sequestering carbon dioxide underground by mineralizing the carbon dioxide with coinjected fluids and minerals remaining from the extraction shale oil. In one embodiment, the oil shale of an illite-rich oil shale is heated to pyrolyze the shale underground, and carbon dioxide is provided to the remaining depleted oil shale while at an elevated temperature. Conditions are sufficient to mineralize the carbon dioxide.

Microbial Enhanced Oil Recovery - Advanced Reservoir Simulation

DEFF Research Database (Denmark)

Nielsen, Sidsel Marie

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

Refined reservoir description to maximize oil recovery

International Nuclear Information System (INIS)

Flewitt, W.E.

1975-01-01

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

Interpreting isotopic analyses of microbial sulfate reduction in oil reservoirs

Science.gov (United States)

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

2013-12-01

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

EOS simulation and GRNN modeling of the constant volume depletion behavior of gas condensate reservoirs

Energy Technology Data Exchange (ETDEWEB)

Elsharkawy, A.M.; Foda, S.G. [Kuwait University, Safat (Kuwait). Petroleum Engineering Dept.

1998-03-01

Currently, two approaches are being used to predict the changes in retrograde gas condensate composition and estimate the pressure depletion behavior of gas condensate reservoirs. The first approach uses the equation of states whereas the second uses empirical correlations. Equations of states (EOS) are poor predictive tools for complex hydrocarbon systems. The EOS needs adjustment against phase behavior data of reservoir fluid of known composition. The empirical correlation does not involve numerous numerical computations but their accuracy is limited. This study presents two general regression neural network (GRNN) models. The first model, GRNNM1, is developed to predict dew point pressure and gas compressibility at dew point using initial composition of numerous samples while the second model, GRNNM2, is developed to predict the changes in well stream effluent composition at any stages of pressure depletion. GRNNM2 can also be used to determine the initial reservoir fluid composition using dew point pressure, gas compressibility at dew point, and reservoir temperature. These models are based on analysis of 142 sample of laboratory studies of constant volume depletion (CVD) for gas condensate systems forming a total of 1082 depletion stages. The database represents a wide range of gas condensate systems obtained worldwide. The performance of the GRNN models has been compared to simulation results of the equation of state. The study shows that the proposed general regression neural network models are accurate, valid, and reliable. These models can be used to forecast CVD data needed for many reservoir engineering calculations in case laboratory data is unavailable. The GRNN models save computer time involved in EOS calculations. The study also show that once these models are properly trained they can be used to cut expenses of frequent sampling and laborious experimental CVD tests required for gas condensate reservoirs. 55 refs., 13 figs., 6 tabs.

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

Science.gov (United States)

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

2015-07-01

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

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

DEFF Research Database (Denmark)

Seyyedi, Mojtaba; Sohrabi, Mehran; Sisson, Adam

2017-01-01

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

Isotopic insights into microbial sulfur cycling in oil reservoirs

Directory of Open Access Journals (Sweden)

Christopher G Hubbard

2014-09-01

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

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

Energy Technology Data Exchange (ETDEWEB)

Beeder, Janiche

1997-12-31

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

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

Energy Technology Data Exchange (ETDEWEB)

Beeder, Janiche

1996-12-31

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

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

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

Energy Technology Data Exchange (ETDEWEB)

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

1999-04-05

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

Characterization of oil and gas reservoir heterogeneity. Final report

Energy Technology Data Exchange (ETDEWEB)

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

1992-10-01

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

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

Study of pressure maintenance in the lower Gassi Touil reservoir

Energy Technology Data Exchange (ETDEWEB)

Ribuot, M.

1969-11-01

The Gassi Touil reservoir in the Sahara is a faulted anticline; the reservoir rock consists of a series of shales and sandstones. It has a primary gas cap in equilibrium with the oil. The oil-gas interface is at 1,642 m; the oil-water interface at 1,970 m. Initial pressure was substantially above hydrostatic. The reservoir contains about 97 million tons STO. A 3-phase, 3-dimensional computer model was used to study the recovery by primary depletion, and by pressure maintenance by gas or water injection. Water injection yields the maximum recovery, but its full efficiency is limited by the fact that only one row of wells can be drilled to the annulus where the wells penetrate only the oil zone. This operation must be supplemented with gas injection into the expanding gas cap in order to efficiently maintain in the reservoir pressure.

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

Energy Technology Data Exchange (ETDEWEB)

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

1995-05-01

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

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.

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

Research on oil recovery mechanisms in heavy oil reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2000-03-16

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

IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

International Nuclear Information System (INIS)

Grigg, Reid B.

2002-01-01

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

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

Directory of Open Access Journals (Sweden)

REZA MASOOMI

2017-01-01

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

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

Despite declining production rates, existing reservoirs in the United States contain vast volumes of remaining oil that is not being effectively recovered. This oil resource constitutes a huge target for the development and application of modern, cost-effective technologies for producing oil. Chief among the barriers to the recovery of this oil are the high costs of designing and implementing conventional advanced recovery technologies in these mature, in many cases pressure-depleted, reservoirs. An additional, increasingly significant barrier is the lack of vital technical expertise necessary for the application of these technologies. This lack of expertise is especially notable among the small operators and independents that operate many of these mature, yet oil-rich, reservoirs. We addressed these barriers to more effective oil recovery by developing, testing, applying, and documenting an innovative technology that can be used by even the smallest operator to significantly increase the flow of oil from mature U.S. reservoirs. The Bureau of Economic Geology and Goldrus Producing Company assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The Permian Basin, the largest oil-bearing basin in North America, contains more than 70 billion barrels of remaining oil in place and is an ideal venue to validate this technology. We have demonstrated the potential of HPAI for oil-recovery improvement in preliminary laboratory tests and a reservoir pilot project. To more completely test the technology, this project emphasized detailed characterization of reservoir properties, which were integrated to access the effectiveness and economics of HPAI. The characterization phase of the project utilized geoscientists and petroleum engineers from the Bureau of Economic Geology and the Department of Petroleum

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

Energy Technology Data Exchange (ETDEWEB)

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

1997-08-01

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

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

KAUST Repository

Jeong, Chanseok

2011-03-01

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

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

NARCIS (Netherlands)

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

2015-01-01

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

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

OpenAIRE

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

2017-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2011-07-01

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

Accounting for Depletion of Oil and Gas Resources in Malaysia

Energy Technology Data Exchange (ETDEWEB)

Othman, Jamal, E-mail: jortman@ukm.my; Jafari, Yaghoob, E-mail: yaghoob.jafari@gmail.com [Universiti Kebangsaan Malaysia, Faculty of Economics and Management (Malaysia)

2012-12-15

Since oil and gas are non-renewable resources, it is important to identify the extent to which they have been depleted. Such information will contribute to the formulation and evaluation of appropriate sustainable development policies. This paper provides an assessment of the changes in the availability of oil and gas resources in Malaysia by first compiling the physical balance sheet for the period 2000-2007, and then assessing the monetary balance sheets for the said resource by using the Net Present Value method. Our findings show serious reduction in the value of oil reserves from 2001 to 2005, due to changes in crude oil prices, and thereafter the depletion rates decreased. In the context of sustainable development planning, albeit in the weak sustainability sense, it will be important to ascertain if sufficient reinvestments of the estimated resource rents in related or alternative capitals are being attempted by Malaysia. For the study period, the cumulative resource rents were to the tune of RM61 billion. Through a depletion or resource rents policy, the estimated quantum may guide the identification of a reinvestment threshold (after considering needed capital investment for future development of the industry) in light of ensuring the future productive capacity of the economy at the time when the resource is exhausted.

Accounting for Depletion of Oil and Gas Resources in Malaysia

International Nuclear Information System (INIS)

Othman, Jamal; Jafari, Yaghoob

2012-01-01

Since oil and gas are non-renewable resources, it is important to identify the extent to which they have been depleted. Such information will contribute to the formulation and evaluation of appropriate sustainable development policies. This paper provides an assessment of the changes in the availability of oil and gas resources in Malaysia by first compiling the physical balance sheet for the period 2000–2007, and then assessing the monetary balance sheets for the said resource by using the Net Present Value method. Our findings show serious reduction in the value of oil reserves from 2001 to 2005, due to changes in crude oil prices, and thereafter the depletion rates decreased. In the context of sustainable development planning, albeit in the weak sustainability sense, it will be important to ascertain if sufficient reinvestments of the estimated resource rents in related or alternative capitals are being attempted by Malaysia. For the study period, the cumulative resource rents were to the tune of RM61 billion. Through a depletion or resource rents policy, the estimated quantum may guide the identification of a reinvestment threshold (after considering needed capital investment for future development of the industry) in light of ensuring the future productive capacity of the economy at the time when the resource is exhausted.

Nuclear stimulation of oil-reservoirs

International Nuclear Information System (INIS)

Delort, F.; Supiot, F.

1970-01-01

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

Nuclear stimulation of oil-reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

1970-05-01

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

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

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.

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.

Electro-magnetic heating in viscous oil reservoir

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

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

Energy Technology Data Exchange (ETDEWEB)

Karaskiewicz, J

1974-01-01

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

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

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

NARCIS (Netherlands)

Salimi, H.

2010-01-01

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

Risk management in oil reservoir water-flooding under economic uncertainty

NARCIS (Netherlands)

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

2015-01-01

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

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

Characterization of oil and gas reservoir heterogeneity

Energy Technology Data Exchange (ETDEWEB)

1991-01-01

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

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.

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.

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

Directory of Open Access Journals (Sweden)

Ju Binshan

2015-11-01

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

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

OpenAIRE

Lu, Hongjiang

2009-01-01

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

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

KAUST Repository

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

2014-01-01

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

Controlled PVTS oil and gas production stimulation system

Energy Technology Data Exchange (ETDEWEB)

Ospina-Racines, E

1970-02-01

By completing oil- or gas-producing wells according to the PVTS method and energizing the flow of the oil-gas fluids in the reservoir with a small horse-power gas compressor at the wellhead, the following oil and gas production features are attained: (1) Original reservoir story energy conditions are restored, improved, used, and conserved while producing oil and/or gas. (2) The flow of oil or gas in the pay formation to the well bore is stimulated by gas compressor energy, outside of the reservoir system. The pressure drawdown is developed by gas-compressor energy in the well casing and not in the pay formation. (3) The stored energy of the reservoir is conserved while producing oil or gas. The potential energy (pressure) of the reservoir can be used to advantage up to bubble point of the virgin crude. (4) Producible reserves are increased from 4-to 5-fold by the conservation of reservoir energy. Present-day primary oil production practice yields a maximum of 20% of the oil in place by depleting the original reservoir energy. The PVTS system will yield over 80% + of oil in place. (5) Producible gas reserves can be increased greatly by establishing a low abandonment pressure at will. The principal features of the PVTS well mechanism and energy injection method are illustrated by a schematic diagram.

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

KAUST Repository

Katterbauer, Klemens

2016-08-25

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

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.

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

Science.gov (United States)

Eid, Mohamed El Gohary

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

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

Science.gov (United States)

Cao, Z.

2015-12-01

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

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

Science.gov (United States)

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

2015-10-01

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

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

KAUST Repository

Hakiki, Farizal

2017-10-17

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

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

KAUST Repository

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

2017-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

Heavy oil reservoirs recoverable by thermal technology. Annual report

Energy Technology Data Exchange (ETDEWEB)

Kujawa, P.

1981-02-01

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

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

Science.gov (United States)

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

2015-11-05

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

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

International Nuclear Information System (INIS)

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

2013-01-01

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

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

Science.gov (United States)

Islam, Nayyer

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

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

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

Science.gov (United States)

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

2018-03-01

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

Prediction of reservoir compaction and surface subsidence

Energy Technology Data Exchange (ETDEWEB)

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

1988-06-01

A new loading-rate-dependent compaction model for unconsolidated clastic reservoirs is presented that considerably improves the accuracy of predicting reservoir rock compaction and surface subsidence resulting from pressure depletion in oil and gas fields. The model has been developed on the basis of extensive laboratory studies and can be derived from a theory relating compaction to time-dependent intergranular friction. The procedure for calculating reservoir compaction from laboratory measurements with the new model is outlined. Both field and laboratory compaction behaviors appear to be described by one single normalized, nonlinear compaction curve. With the new model, the large discrepancies usually observed between predictions based on linear compaction models and actual (nonlinear) field behavior can be explained.

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

International Nuclear Information System (INIS)

Han, Weon Shik; McPherson, Brian J.

2009-01-01

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

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

KAUST Repository

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

2011-01-01

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

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

Science.gov (United States)

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

2016-10-01

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

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.

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

International Nuclear Information System (INIS)

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

2013-01-01

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

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.)

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

NARCIS (Netherlands)

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

2018-01-01

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

Origin of late pleistocene formation water in Mexican oil reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2004-07-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

A Time Domain Update Method for Reservoir History Matching of Electromagnetic Data

KAUST Repository

Katterbauer, Klemens

2014-03-25

The oil & gas industry has been the backbone of the world\\'s economy in the last century and will continue to be in the decades to come. With increasing demand and conventional reservoirs depleting, new oil industry projects have become more complex and expensive, operating in areas that were previously considered impossible and uneconomical. Therefore, good reservoir management is key for the economical success of complex projects requiring the incorporation of reliable uncertainty estimates for reliable production forecasts and optimizing reservoir exploitation. Reservoir history matching has played here a key role incorporating production, seismic, electromagnetic and logging data for forecasting the development of reservoirs and its depletion. With the advances in the last decade, electromagnetic techniques, such as crosswell electromagnetic tomography, have enabled engineers to more precisely map the reservoirs and understand their evolution. Incorporating the large amount of data efficiently and reducing uncertainty in the forecasts has been one of the key challenges for reservoir management. Computing the conductivity distribution for the field for adjusting parameters in the forecasting process via solving the inverse problem has been a challenge, due to the strong ill-posedness of the inversion problem and the extensive manual calibration required, making it impossible to be included into an efficient reservoir history matching forecasting algorithm. In the presented research, we have developed a novel Finite Difference Time Domain (FDTD) based method for incorporating electromagnetic data directly into the reservoir simulator. Based on an extended Archie relationship, EM simulations are performed for both forecasted and Porosity-Saturation retrieved conductivity parameters being incorporated directly into an update step for the reservoir parameters. This novel direct update method has significant advantages such as that it overcomes the expensive and ill

Modeling CO₂ Sequestration in Saline Aquifer and Depleted Oil Reservoir To Evaluate Regional CO₂ Sequestration Potential of Ozark Plateau Aquifer System, South-Central Kansas

Energy Technology Data Exchange (ETDEWEB)

Watney, W. Lynn [University Of Kansas Center For Research, Inc. Lawrence, KS (United States); Rush, Jason [University Of Kansas Center For Research, Inc. Lawrence, KS (United States); Raney, Jennifer [University Of Kansas Center For Research, Inc. Lawrence, KS (United States)

2014-09-30

1. Drilled, cored, and logged three wells to the basement and collecting more than 2,700 ft of conventional core; obtained 20 mⁱ² of multicomponent 3D seismic imaging and merged and reprocessed more than 125 mi² of existing 3D seismic data for use in modeling CO₂- EOR oil recovery and CO₂ storage in five oil fields in southern Kansas. 2. Determined the technical feasibility of injecting and sequestering CO₂ in a set of four depleted oil reservoirs in the Cutter, Pleasant Prairie South, Eubank, and Shuck fields in southwest Kansas; of concurrently recovering oil from those fields; and of quantifying the volumes of CO2 sequestered and oil recovered during the process. 3. Formed a consortium of six oil operating companies, five of which own and operate the four fields. The consortium became part of the Southwest Kansas CO₂-EOR Initiative for the purpose of sharing data, knowledge, and interest in understanding the potential for CO₂-EOR in Kansas. 4. Built a regional well database covering 30,000 mi² and containing stratigraphic tops from ~90,000 wells; correlated 30 major stratigraphic horizons; digitized key wells, including wireline logs and sample logs; and analyzed more than 3,000 drill stem tests to establish that fluid levels in deep aquifers below the Permian evaporites are not connected to the surface and therefore pressures are not hydrostatic. Connectivity with the surface aquifers is lacking because shale aquitards and impermeable evaporite layers consist of both halite and anhydrite. 5. Developed extensive web applications and an interactive mapping system that do the following: a. Facilitate access to a wide array of data obtained in the study, including core descriptions and analyses, sample logs, digital (LAS) well logs, seismic data, gravity and magnetics maps, structural and stratigraphic maps, inferred fault traces, earthquakes, Class I and II disposal wells, and

Modeling CO₂ Sequestration in Saline Aquifer and Depleted Oil Reservoir To Evaluate Regional CO₂ Sequestration Potential of Ozark Plateau Aquifer System, South-Central Kansas

Energy Technology Data Exchange (ETDEWEB)

Watney, W. Lynn [University Of Kansas Center For Research, Inc. Lawrence, KS (United States)

2014-09-30

1. Drilled, cored, and logged three wells to the basement and collecting more than 2,700 ft of conventional core; obtained 20 mⁱ² of multicomponent 3D seismic imaging and merged and reprocessed more than 125 mi² of existing 3D seismic data for use in modeling CO₂- EOR oil recovery and CO₂ storage in five oil fields in southern Kansas. 2. Determined the technical feasibility of injecting and sequestering CO₂ in a set of four depleted oil reservoirs in the Cutter, Pleasant Prairie South, Eubank, and Shuck fields in southwest Kansas; of concurrently recovering oil from those fields; and of quantifying the volumes of CO2 sequestered and oil recovered during the process. 3. Formed a consortium of six oil operating companies, five of which own and operate the four fields. The consortium became part of the Southwest Kansas CO₂-EOR Initiative for the purpose of sharing data, knowledge, and interest in understanding the potential for CO₂-EOR in Kansas. 4. Built a regional well database covering 30,000 mi² and containing stratigraphic tops from ~90,000 wells; correlated 30 major stratigraphic horizons; digitized key wells, including wireline logs and sample logs; and analyzed more than 3,000 drill stem tests to establish that fluid levels in deep aquifers below the Permian evaporites are not connected to the surface and therefore pressures are not hydrostatic. Connectivity with the surface aquifers is lacking because shale aquitards and impermeable evaporite layers consist of both halite and anhydrite. 5. Developed extensive web applications and an interactive mapping system that do the following: a. Facilitate access to a wide array of data obtained in the study, including core descriptions and analyses, sample logs, digital (LAS) well logs, seismic data, gravity and magnetics maps, structural and stratigraphic maps, inferred fault traces, earthquakes, Class I and II disposal wells, and

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.

Depleted Hydrocarbon Reservoirs Present a Safe and Practical Burial Solution for Graphite Waste

International Nuclear Information System (INIS)

Rahmani, L.

2016-01-01

A solution for graphite waste is proposed that combines reliance on thick impermeable host rock that is needed to confine the long-life radioactivity content of most irradiated graphite with low capitalistic and operational unit volume costs that are required to render this bulky waste form manageable. The solution, uniquely applicable to irradiated graphite due to its low dose rates, moderate mechanical strength and light density, consists in three steps: first, graphite is fine-crushed under water; second, it is made in an aqueous suspension; third, the suspension is injected into a deep, disused hydrocarbon reservoir. Each of these steps only involves well mastered techniques. Regulatory changes that may allow this solution to be added to the gamut of available waste routes, geochemical issues, availability of depleted reservoirs and cost projections are presented. (author)

IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

Energy Technology Data Exchange (ETDEWEB)

Reid B. Grigg

2003-10-31

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

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

Science.gov (United States)

Attanasi, E.D.

2016-01-01

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

Effect of hypolimnetic oxygenation on oxygen depletion rates in two water-supply reservoirs.

Science.gov (United States)

Gantzer, Paul A; Bryant, Lee D; Little, John C

2009-04-01

Oxygenation systems, such as bubble-plume diffusers, are used to improve water quality by replenishing dissolved oxygen (DO) in the hypolimnia of water-supply reservoirs. The diffusers induce circulation and mixing, which helps distribute DO throughout the hypolimnion. Mixing, however, has also been observed to increase hypolimnetic oxygen demand (HOD) during system operation, thus accelerating oxygen depletion. Two water-supply reservoirs (Spring Hollow Reservoir (SHR) and Carvins Cove Reservoir (CCR)) that employ linear bubble-plume diffusers were studied to quantify diffuser effects on HOD. A recently validated plume model was used to predict oxygen addition rates. The results were used together with observed oxygen accumulation rates to evaluate HOD over a wide range of applied gas flow rates. Plume-induced mixing correlated well with applied gas flow rate and was observed to increase HOD. Linear relationships between applied gas flow rate and HOD were found for both SHR and CCR. HOD was also observed to be independent of bulk hypolimnion oxygen concentration, indicating that HOD is controlled by induced mixing. Despite transient increases in HOD, oxygenation caused an overall decrease in background HOD, as well as a decrease in induced HOD during diffuser operation, over several years. This suggests that the residual or background oxygen demand decreases from one year to the next. Despite diffuser-induced increases in HOD, hypolimnetic oxygenation remains a viable method for replenishing DO in thermally-stratified water-supply reservoirs such as SHR and CCR.

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

Directory of Open Access Journals (Sweden)

Jiahang Wang

2017-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

Abbasov, A A; Kasimov, Sh A

1965-01-01

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

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

KAUST Repository

Jeong, C.

2015-05-01

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

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

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

OpenAIRE

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

2016-01-01

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

Ranking oil viscosity in heavy-oil reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2005-11-01

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

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

International Nuclear Information System (INIS)

Allison, Edith

1996-12-01

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

SOVENT BASED ENHANCED OIL RECOVERY FOR IN-SITU UPGRADING OF HEAVY OIL SANDS

Energy Technology Data Exchange (ETDEWEB)

Munroe, Norman

2009-01-30

With the depletion of conventional crude oil reserves in the world, heavy oil and bitumen resources have great potential to meet the future demand for petroleum products. However, oil recovery from heavy oil and bitumen reservoirs is much more difficult than that from conventional oil reservoirs. This is mainly because heavy oil or bitumen is partially or completely immobile under reservoir conditions due to its extremely high viscosity, which creates special production challenges. In order to overcome these challenges significant efforts were devoted by Applied Research Center (ARC) at Florida International University and The Center for Energy Economics (CEE) at the University of Texas. A simplified model was developed to assess the density of the upgraded crude depending on the ratio of solvent mass to crude oil mass, temperature, pressure and the properties of the crude oil. The simplified model incorporated the interaction dynamics into a homogeneous, porous heavy oil reservoir to simulate the dispersion and concentration of injected CO2. The model also incorporated the characteristic of a highly varying CO2 density near the critical point. Since the major challenge in heavy oil recovery is its high viscosity, most researchers have focused their investigations on this parameter in the laboratory as well as in the field resulting in disparaging results. This was attributed to oil being a complex poly-disperse blend of light and heavy paraffins, aromatics, resins and asphaltenes, which have diverse behaviors at reservoir temperature and pressures. The situation is exacerbated by a dearth of experimental data on gas diffusion coefficients in heavy oils due to the tedious nature of diffusivity measurements. Ultimately, the viscosity and thus oil recovery is regulated by pressure and its effect on the diffusion coefficient and oil swelling factors. The generation of a new phase within the crude and the differences in mobility between the new crude matrix and the

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

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

Science.gov (United States)

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

2016-03-02

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

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

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

DEFF Research Database (Denmark)

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

2012-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

1981-01-01

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

Tracer applications in oil reservoirs in Brazil

International Nuclear Information System (INIS)

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

2004-01-01

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

Extended application of radon as a natural tracer in oil reservoirs

Directory of Open Access Journals (Sweden)

Moreira R.M.

2013-05-01

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

Well test mathematical model for fractures network in tight oil reservoirs

Science.gov (United States)

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

2018-02-01

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

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

Science.gov (United States)

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

2017-11-16

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

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

International Nuclear Information System (INIS)

Eriksen, D.Oe.; Bjoernstad, V.

1999-01-01

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

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

Science.gov (United States)

Varjani, Sunita J; Gnansounou, Edgard

2017-12-01

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

Well selection in depleted oil and gas fields for a safe CO2 storage practice: A case study from Malaysia

Directory of Open Access Journals (Sweden)

Arshad Raza

2017-03-01

Full Text Available Carbon capture and sequestration technology is recognized as a successful approach taken to mitigate the amount of greenhouse gases released into the atmosphere. However, having a successful storage practice requires wise selection of suitable wells in depleted oil or gas fields to reduce the risk of leakage and contamination of subsurface resources. The aim of this paper is to present a guideline which can be followed to provide a better understanding of sophisticated wells chosen for injection and storage practices. Reviewing recent studies carried out on different aspects of geosequestration indicated that the fracture pressure of seals and borehole conditions such as cement-sheath integrity, distance from faults and fractures together with the depth of wells are important parameters, which should be part of the analysis for well selection in depleted reservoirs. A workflow was then designed covering these aspects and it was applied to a depleted gas field in Malaysia. The results obtained indicated that Well B in the field may have the potential of being a suitable conduit for injection. Although more studies are required to consider other aspects of well selections, it is recommended to employ the formation integrity analysis as part of the caprock assessment before making any decisions.

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

Energy Technology Data Exchange (ETDEWEB)

Koerner, Roy; Clarke, Don; Walker, Scott

1999-11-09

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

Experiences with linear solvers for oil reservoir simulation problems

Energy Technology Data Exchange (ETDEWEB)

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

1996-12-31

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

Analysis of real-time reservoir monitoring : reservoirs, strategies, & modeling.

Energy Technology Data Exchange (ETDEWEB)

Mani, Seethambal S.; van Bloemen Waanders, Bart Gustaaf; Cooper, Scott Patrick; Jakaboski, Blake Elaine; Normann, Randy Allen; Jennings, Jim (University of Texas at Austin, Austin, TX); Gilbert, Bob (University of Texas at Austin, Austin, TX); Lake, Larry W. (University of Texas at Austin, Austin, TX); Weiss, Chester Joseph; Lorenz, John Clay; Elbring, Gregory Jay; Wheeler, Mary Fanett (University of Texas at Austin, Austin, TX); Thomas, Sunil G. (University of Texas at Austin, Austin, TX); Rightley, Michael J.; Rodriguez, Adolfo (University of Texas at Austin, Austin, TX); Klie, Hector (University of Texas at Austin, Austin, TX); Banchs, Rafael (University of Texas at Austin, Austin, TX); Nunez, Emilio J. (University of Texas at Austin, Austin, TX); Jablonowski, Chris (University of Texas at Austin, Austin, TX)

2006-11-01

survivability issues. Our findings indicate that packaging represents the most significant technical challenge associated with application of sensors in the downhole environment for long periods (5+ years) of time. These issues are described in detail within the report. The impact of successful reservoir monitoring programs and coincident improved reservoir management is measured by the production of additional oil and gas volumes from existing reservoirs, revitalization of nearly depleted reservoirs, possible re-establishment of already abandoned reservoirs, and improved economics for all cases. Smart Well monitoring provides the means to understand how a reservoir process is developing and to provide active reservoir management. At the same time it also provides data for developing high-fidelity simulation models. This work has been a joint effort with Sandia National Laboratories and UT-Austin's Bureau of Economic Geology, Department of Petroleum and Geosystems Engineering, and the Institute of Computational and Engineering Mathematics.

Depletion - flocculation in oil-in-water emulsions using fibrillar protein assemblies

NARCIS (Netherlands)

Blijdenstein, T.B.J.; Veerman, C.; Linden, van der E.

2004-01-01

This paper shows that low concentrations of -lactoglobulin fibrils can induce depletion-flocculation in -lactoglobulin-stabilized oil-in-water emulsions. The minimum required fibril concentration for flocculation was determined experimentally for fibril lengths of about 3 and 0.1 m. The minimum

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

International Nuclear Information System (INIS)

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

1999-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

Teodoriu, Catalin; Falcone, Gioia; Espinel, Arnaldo

2007-07-01

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

Well performance relationships in heavy foamy oil reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

WCB - the little oil patch that could

International Nuclear Information System (INIS)

Knoll, R. G.

1999-01-01

The globally dominant position of the Western Canadian Basin (WCB) in innovative exploitation technology (horizontal wells) and the major role it plays in related technical pursuits (underbalanced drilling, extended reach drilling, coiled tubing and multi-branch technology) are discussed. This enviable position has been gained despite the fact that in comparison to the world's major producing areas, the WCB is a region of relatively thin, varied, depleted reservoirs of limited reserves and meagre profit margins. Yet in this marginal setting, oil production increased over 90 per cent in the last decade, in large part due to the exponential growth of horizontal well applications. It is argued that Canada's leadership in exploitation technology is not simply a result of the thin, depleted reservoirs, but is promoted by a combination of many factors, foremost among them being a collective spirit of co-operation and innovation among the oil companies. The variance in reservoir setting, the corporate culture, the entrepreneurial spirit, a competitive service market, extremes of environment, a stable political and economic framework close to the largest diversified markets (i.e. the USA) also have played important contributory roles. 3 refs., 1 tab

The tug-of-war between resource depletion and technological change in the global oil industry 1981-2009

Energy Technology Data Exchange (ETDEWEB)

Lindholt, Lars

2013-01-15

We perform an empirical analysis of the extent to which ongoing technological change through RandD activity has offset the effect of ongoing depletion on the cost of finding additional reserves of oil in eight global regions. We introduce a finding cost function that among other factors depends on the cumulative number of past RandD expenses and cumulative past production, measuring technological change and depletion, respectively. For all our regions we find significant effects of both depletion and technological change on oil finding costs from 1981 to 2009, barring cyclical variations in finding costs that could come from changes in factor prices. For almost all regions technology more than mitigated depletion until around the mid-nineties. However, we find that depletion outweighed technological progress over the last decade.(author)

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)

A New Screening Methodology for Improved Oil Recovery Processes Using Soft-Computing Techniques

Science.gov (United States)

Parada, Claudia; Ertekin, Turgay

2010-05-01

The first stage of production of any oil reservoir involves oil displacement by natural drive mechanisms such as solution gas drive, gas cap drive and gravity drainage. Typically, improved oil recovery (IOR) methods are applied to oil reservoirs that have been depleted naturally. In more recent years, IOR techniques are applied to reservoirs even before their natural energy drive is exhausted by primary depletion. Descriptive screening criteria for IOR methods are used to select the appropriate recovery technique according to the fluid and rock properties. This methodology helps in assessing the most suitable recovery process for field deployment of a candidate reservoir. However, the already published screening guidelines neither provide information about the expected reservoir performance nor suggest a set of project design parameters, which can be used towards the optimization of the process. In this study, artificial neural networks (ANN) are used to build a high-performance neuro-simulation tool for screening different improved oil recovery techniques: miscible injection (CO2 and N2), waterflooding and steam injection processes. The simulation tool consists of proxy models that implement a multilayer cascade feedforward back propagation network algorithm. The tool is intended to narrow the ranges of possible scenarios to be modeled using conventional simulation, reducing the extensive time and energy spent in dynamic reservoir modeling. A commercial reservoir simulator is used to generate the data to train and validate the artificial neural networks. The proxy models are built considering four different well patterns with different well operating conditions as the field design parameters. Different expert systems are developed for each well pattern. The screening networks predict oil production rate and cumulative oil production profiles for a given set of rock and fluid properties, and design parameters. The results of this study show that the networks are

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

Impact of an indigenous microbial enhanced oil recovery field trial on microbial community structure in a high pour-point oil reservoir

Energy Technology Data Exchange (ETDEWEB)

Zhang, Fan; Zhang, Xiao-Tao; Hou, Du-Jie [China Univ. of Geosciences, Beijing (China). The Key Lab. of Marine Reservoir Evolution and Hydrocarbon Accumulation Mechanism; She, Yue-Hui [Yangtze Univ., Jingzhou, Hubei (China). College of Chemistry and Environmental Engineering; Huazhong Univ. of Science and Technology, Wuhan (China). College of Life Science and Technology; Li, Hua-Min [Beijing Bioscience Research Center (China); Shu, Fu-Chang; Wang, Zheng-Liang [Yangtze Univ., Jingzhou, Hubei (China). College of Chemistry and Environmental Engineering; Yu, Long-Jiang [Huazhong Univ. of Science and Technology, Wuhan (China). College of Life Science and Technology

2012-08-15

Based on preliminary investigation of microbial populations in a high pour-point oil reservoir, an indigenous microbial enhanced oil recovery (MEOR) field trial was carried out. The purpose of the study is to reveal the impact of the indigenous MEOR process on microbial community structure in the oil reservoir using 16Sr DNA clone library technique. The detailed monitoring results showed significant response of microbial communities during the field trial and large discrepancies of stimulated microorganisms in the laboratory and in the natural oil reservoir. More specifically, after nutrients injection, the original dominant populations of Petrobacter and Alishewanella in the production wells almost disappeared. The expected desirable population of Pseudomonas aeruginosa, determined by enrichment experiments in laboratory, was stimulated successfully in two wells of the five monitored wells. Unexpectedly, another potential population of Pseudomonas pseudoalcaligenes which were not detected in the enrichment culture in laboratory was stimulated in the other three monitored production wells. In this study, monitoring of microbial community displayed a comprehensive alteration of microbial populations during the field trial to remedy the deficiency of culture-dependent monitoring methods. The results would help to develop and apply more MEOR processes. (orig.)

Impact of an indigenous microbial enhanced oil recovery field trial on microbial community structure in a high pour-point oil reservoir.

Science.gov (United States)

Zhang, Fan; She, Yue-Hui; Li, Hua-Min; Zhang, Xiao-Tao; Shu, Fu-Chang; Wang, Zheng-Liang; Yu, Long-Jiang; Hou, Du-Jie

2012-08-01

Based on preliminary investigation of microbial populations in a high pour-point oil reservoir, an indigenous microbial enhanced oil recovery (MEOR) field trial was carried out. The purpose of the study is to reveal the impact of the indigenous MEOR process on microbial community structure in the oil reservoir using 16Sr DNA clone library technique. The detailed monitoring results showed significant response of microbial communities during the field trial and large discrepancies of stimulated microorganisms in the laboratory and in the natural oil reservoir. More specifically, after nutrients injection, the original dominant populations of Petrobacter and Alishewanella in the production wells almost disappeared. The expected desirable population of Pseudomonas aeruginosa, determined by enrichment experiments in laboratory, was stimulated successfully in two wells of the five monitored wells. Unexpectedly, another potential population of Pseudomonas pseudoalcaligenes which were not detected in the enrichment culture in laboratory was stimulated in the other three monitored production wells. In this study, monitoring of microbial community displayed a comprehensive alteration of microbial populations during the field trial to remedy the deficiency of culture-dependent monitoring methods. The results would help to develop and apply more MEOR processes.

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

Science.gov (United States)

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

2016-01-01

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

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

Directory of Open Access Journals (Sweden)

Hao Dong

2016-11-01

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

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

Science.gov (United States)

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

2016-01-01

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

Geologic storage of carbon dioxide and enhanced oil recovery. I. Uncertainty quantification employing a streamline based proxy for reservoir flow simulation

International Nuclear Information System (INIS)

Kovscek, A.R.; Wang, Y.

2005-01-01

Carbon dioxide (CO 2 ) is already injected into a limited class of reservoirs for oil recovery purposes; however, the engineering design question for simultaneous oil recovery and storage of anthropogenic CO 2 is significantly different from that of oil recovery alone. Currently, the volumes of CO 2 injected solely for oil recovery are minimized due to the purchase cost of CO 2 . If and when CO 2 emissions to the atmosphere are managed, it will be necessary to maximize simultaneously both economic oil recovery and the volumes of CO 2 emplaced in oil reservoirs. This process is coined 'cooptimization'. This paper proposes a work flow for cooptimization of oil recovery and geologic CO 2 storage. An important component of the work flow is the assessment of uncertainty in predictions of performance. Typical methods for quantifying uncertainty employ exhaustive flow simulation of multiple stochastic realizations of the geologic architecture of a reservoir. Such approaches are computationally intensive and thereby time consuming. An analytic streamline based proxy for full reservoir simulation is proposed and tested. Streamline trajectories represent the three-dimensional velocity field during multiphase flow in porous media and so are useful for quantifying the similarity and differences among various reservoir models. The proxy allows rational selection of a representative subset of equi-probable reservoir models that encompass uncertainty with respect to true reservoir geology. The streamline approach is demonstrated to be thorough and rapid

IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

International Nuclear Information System (INIS)

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

2004-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2000-06-08

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

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

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

Science.gov (United States)

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

2016-12-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2012-07-01

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

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.

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

Science.gov (United States)

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

2018-06-01

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

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.

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

Energy Technology Data Exchange (ETDEWEB)

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

1996-05-01

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

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

Directory of Open Access Journals (Sweden)

Jenna L Shelton

2016-09-01

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

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.

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

Science.gov (United States)

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

1992-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2005-01-15

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

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

Energy Technology Data Exchange (ETDEWEB)

Doublet, Daniel Christopher

2007-07-01

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

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.

Thermal enhanced oil recovery in Indonesia. Prospect of HTGR application

International Nuclear Information System (INIS)

Rahman, M.; Sumardiono; Lasman, A.N.; Sudarto; Prihardany, D.

1997-01-01

In the next future, Indonesia will face oil scarcity. The present reserves are estimated to be depleted in 20 years. However, after primary and secondary recovery processes, there are still more than 50% of original oil in place remaining in the reservoir, and this could be recovered by using tertiary recovery method or which is known as enhanced oil recovery (EOR) processes. Among the three major methods of EOR, steam flooding is a thermal recovery method into which High Temperature Reactor (HTR) module can be integrated for producing steam. However, the feasibility of application of HTR as an alternative to conventional oil-fired steam generator will depend strongly on the price of oil. This paper discusses EOR screening for Indonesian oil fields to identify the appropriate oil reservoirs for steam flooding application as well as the possibility of steam supply by HTR module. Also reviewed is the previous study on HTR application for Duri Steam Flood Project. (author). 8 refs, 6 figs, 5 tabs

Expanding solvent SAGD in heavy oil reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

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

Science.gov (United States)

Yin, Jie; Xiong, Ting

2018-01-01

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

Recovery enhancement at the later stage of supercritical condensate gas reservoir development via CO2 injection: A case study on Lian 4 fault block in the Fushan sag, Beibuwan Basin

Directory of Open Access Journals (Sweden)

Wenyan Feng

2016-11-01

Full Text Available Lian 4 fault block is located in the northwest of Fushan sag, Beibuwan Basin. It is a high-saturated condensate gas reservoir with rich condensate oil held by three faults. In order to seek an enhanced condensate oil recovery technology that is suitable for this condensate gas reservoir at its later development stage, it is necessary to analyze its reserve producing degree and remaining development potential after depletion production, depending on the supercritical fluid phase behavior and depletion production performance characteristics. The supercritical fluid theories and multiple reservoir engineering dynamic analysis methods were adopted comprehensively, such as dynamic reserves, production decline, liquid-carrying capacity of a production well, and remaining development potential analysis. It is shown that, at its early development stage, the condensate in Lian 4 fault block presented the features of supercritical fluid, and the reservoir pressure was lower than the dew point pressure, so retrograde condensate loss was significant. Owing to the retrograde condensate effect and the fast release of elastic energy, the reserve producing degree of depletion production is low in Lian 4 fault block, and 80% of condensate oil still remains in the reservoir. So, the remaining development potential is great. The supercritical condensate in Lian 4 fault block is of high density. Based on the optimization design by numerical simulation of compositional model, it is proposed to inject CO2 at the top and build up pressure by alternating production and injection, so that the secondary gas cap is formed while the gravity-stable miscible displacement is realized. In this way, the recovery factor of condensate reservoirs can be improved by means of the secondary development technology.

Study on distribution of reservoir endogenous microbe and oil displacement mechanism

Directory of Open Access Journals (Sweden)

Ming Yue

2017-02-01

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

Bioemulsan Production by Iranian Oil Reservoirs Microorganisms

Directory of Open Access Journals (Sweden)

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

2004-10-01

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

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

International Nuclear Information System (INIS)

Gawusu, S.

2015-07-01

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

Performance of thermal solvent process in Athabasca reservoir

Energy Technology Data Exchange (ETDEWEB)

Das, Swapan [Marathon Oil (Canada)

2011-07-01

In the petroleum industry, due to depletion of conventional resources and high demand operators are looking into heavy oil and bitumen production. Different recovery methods exist, some of them based on heating the reservoir and others on the use of solvent. Thermal solvent process is a combination of both: a small amount of heat is used to maintain a solvent vapor phase in the reservoir. This process has advantages, solvent is mostly recycled which increases bitumen recovery efficiency and reduces the need for fresh solvent, but it also poses challenges, such as maintaining a vapor chamber and the fact that solvent solubility might be affected by heating. The aim of this paper is to discuss these issues. Simulations and field tests were conducted on bitumen in the the Athabasca region. This paper presented a thermal solvent process and its application's results in Athabasca reservoir.

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

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

DEFF Research Database (Denmark)

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

2003-01-01

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

The PTRC : a world leader in enhanced heavy oil recovery

Energy Technology Data Exchange (ETDEWEB)

Kristoff, B.; Knudsen, R.; Asghari, K. [Petroleum Technology Research Centre, Regina, SK (Canada); Pappas, E.S. [Saskatchewan Research Council, Saskatoon, SK (Canada)

2006-07-01

The Petroleum Technology Research Centre (PTRC) fosters knowledge and progressive technologies to enhance the recovery of petroleum. This paper discussed the PTRC's leadership in enhanced heavy oil recovery, with particular reference to core research program such as heavy oil (post) cold flow; enhanced waterflooding; miscible/immiscible solvent injection; and near-wellbore conformance control. Other projects that were presented included a joint implementation of vapour extraction project (JIVE); and the IEA greenhouse gas (GHG) Weyburn-Midale carbon dioxide monitoring and storage project. The JIVE project will develop, demonstrate and evaluate solvent vapour extraction processes for enhanced oil recovery in heavy oil reservoirs. The GHG Weyburn-Midale project, launched in 2000, studies carbon dioxide injection and storage in partially depleted oil reservoirs. It was concluded that the PTRC continues to develop technologies to meet the world's energy requirements while mitigating both immediate and long-term environmental impacts. 4 figs.

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

Science.gov (United States)

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

2015-01-01

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

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

International Nuclear Information System (INIS)

Murphy, Mark B.

1999-01-01

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

Tectonic control in source rock maturation and oil migration in Trinidad

Energy Technology Data Exchange (ETDEWEB)

Persad, K.M.; Talukdar, S.C.; Dow, W.G. (DGSI, The Woodlands, TX (United States))

1993-02-01

Oil accumulation in Trinidad were sourced by the Upper Cretaceous calcareous shales deposited along the Cretaceous passive margin of northern South America. Maturation of these source rocks, oil generation, migration and re-migration occurred in a foreland basin setting that resulted from interaction between Caribbean and South American plates during Late Oligocene to recent times. During Middle Miocene-Recent times, the foreland basin experienced strong compressional events, which controlled generation, migration, and accumulation of oil in Trinidad. A series of mature source rock kitchens formed in Late Miocene-Recent times in the Southern and Colombus Basins to the east-southeast of the Central Range Thrust. This thrust and associated fratured developed around 12 m.y.b.p. and served as vertical migration paths for the oil generated in Late Miocene time. This oil migrated into submarine fans deposited in the foreland basin axis and older reservoirs deformed into structural traps. Further generation and migration of oil, and re-migration of earlier oil took place during Pliocene-Holocene times, when later thrusting and wrench faulting served as vertical migration paths. Extremely high sedimentation rates in Pliocene-Pleistocene time, concurrent with active faulting, was responsible for very rapid generation of oil and gas. Vertically migrating gas often mixed with earlier migrated oil in overlying reservoirs. This caused depletion of oil in light hydrocarbons with accompanied fractionation among hydrocarbon types resulting in heavier oil in lower reservoirs, enrichment of light hydrocarbons and accumulation of gas-condensates in upper reservoirs. This process led to an oil-gravity stratification within about 10,000 ft of section.

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

Science.gov (United States)

Maojin, Tan; Youlong, Zou; Guoyue

2012-09-01

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

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

Science.gov (United States)

Toledo; Araujo; Leon

1996-11-10

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

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

Directory of Open Access Journals (Sweden)

Jan Dolfing

2017-12-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

1997-08-01

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

Production Optimization of Oil Reservoirs

DEFF Research Database (Denmark)

Völcker, Carsten

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

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

International Nuclear Information System (INIS)

Gabitto, Jorge; Barrufet, Maria

2002-01-01

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

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

Science.gov (United States)

Chang, Yan; Liu, Dameng; Yao, Yanbin

2018-01-01

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

Multigrid methods for fully implicit oil reservoir simulation

Energy Technology Data Exchange (ETDEWEB)

Molenaar, J.

1995-12-31

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

Evidence for the microbial in situ conversion of oil to methane in the Dagang oilfield

Energy Technology Data Exchange (ETDEWEB)

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

2013-08-01

In situ biotransformation of oil to methane was investigated in a reservoir in Dagang, China using chemical fingerprinting, isotopic analyses, and molecular and biological methods. The reservoir is highly methanogenic despite chemical indications of advanced oil degradation, such as depletion of n-alkanes, alkylbenzenes, and light polycyclic aromatic hydrocarbon (PAHs) fractions or changes in the distribution of several alkylated polycyclic aromatic hydrocarbons. The degree of degradation strongly varied between different parts of the reservoir, ranging from severely degraded to nearly undegraded oil compositions. Geochemical data from oil, water and gas samples taken from the reservoir are consistent with in situ biogenic methane production linked to aliphatic and aromatic hydrocarbon degradation. Microcosms were inoculated with production and injection waters in order to characterize these processes in vitro. Subsequent degradation experiments revealed that autochthonous microbiota are capable of producing methane from {sup 13}C-labelled n-hexadecane or 2-methylnaphthalene, and suggest that further methanogenesis may occur from the aromatic and polyaromatic fractions of Dagang reservoir fluids. The microbial communities from produced oil-water samples were composed of high numbers of microorganisms (on the order to 10{sup 7}), including methane-producing Archaea within the same order of magnitude. In summary, the investigated sections of the Dagang reservoir may have significant potential for testing the viability of in situ conversion of oil to methane as an enhanced recovery method, and biodegradation of the aromatic fractions of the oil may be an important methane source. (orig.)

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

Energy Technology Data Exchange (ETDEWEB)

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

1997-06-01

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

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

Science.gov (United States)

Georges Lwisa, Essa; Abdulkhalek, Ashrakat R.

2018-03-01

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

Viscous fingering effects in solvent displacement of heavy oil

Energy Technology Data Exchange (ETDEWEB)

Cuthiell, D. [Suncor Energy, Fort McMurray, AB (Canada); Kissel, G.; Jackson, C.; Frauenfeld, T.W.J.; Fisher, D. [Alberta Research Council, Devon, AB (Canada); Rispler, K. [Saskatchewan Research Council, Saskatoon, SK (Canada)

2004-07-01

Vapour Extraction (VAPEX) is a solvent-based process that is analogous to steam-assisted gravity drainage (SAGD) for the recovery of heavy oil. A cyclic solvent process is preferred for thin reservoirs, particularly primary-depleted reservoirs. In a cyclic steam stimulation process, a solvent is injected into the reservoir for a period of time before oil is produced from the well. Viscous fingering is a phenomena that characterizes several solvent-based processes for the recovery of heavy oil. A combined experimental and simulation study was conducted to characterize viscous fingering under heavy oil recovery conditions (high ratio of oil to solvent viscosity). Four experiments were conducted in heavy oil-saturated sand packs. Three involved injection of a miscible, liquid solvent at the bottom of the sand pack. The heavy oil in these experiments was displaced upwardly. The fourth experiment involved top-down injection of a gaseous solvent. The miscible liquid displacement was dominated by one solvent finger which broke through to a producing well at the other end of the sand pack. Breakthrough times were similar to that at lower viscosity. The fourth experiment showed fingering along with features of a gravity-driven VAPEX process. Key features of the experiment and realistic fingering patterns were numerically simulated using a commercial reservoir simulator. It was emphasized that accurate modelling of dispersion is necessary in matching the observed phenomena. The simulations should include the capillary effects because of their significance for gaseous fingering and the VAPEX processes. 17 refs., 2 tabs., 20 figs.

Review of flow rate estimates of the Deepwater Horizon oil spill

OpenAIRE

McNutt, Marcia K.; Camilli, Rich; Crone, Timothy J.; Guthrie, George D.; Hsieh, Paul A.; Ryerson, Thomas B.; Savas, Omer; Shaffer, Frank

2011-01-01

The unprecedented nature of the Deepwater Horizon oil spill required the application of research methods to estimate the rate at which oil was escaping from the well in the deep sea, its disposition after it entered the ocean, and total reservoir depletion. Here, we review what advances were made in scientific understanding of quantification of flow rates during deep sea oil well blowouts. We assess the degree to which a consensus was reached on the flow rate of the well by comparing in situ ...

Competitive, microbially-mediated reduction of nitrate with sulfide and aromatic oil components in a low-temperature, western Canadian oil reservoir.

Science.gov (United States)

Lambo, Adewale J; Noke, Kim; Larter, Steve R; Voordouw, Gerrit

2008-12-01

Fields from which oil is produced by injection of sulfate-bearing water often exhibit an increase in sulfide concentration with time (souring). Nitrate added to the injection water lowers the sulfide concentration by the action of sulfide-oxidizing, nitrate-reducing bacteria (SO-NRB). However, the injected nitrate can also be reduced with oil organics by heterotrophic NRB (hNRB). Aqueous volatile fatty acids (VFAs; a mixture of acetate, propionate, and butyrate) are considered important electron donors in this regard. Injection and produced waters from a western Canadian oil field with a low in situ reservoir temperature (30 degrees C) had only 0.1-0.2 mM VFAs. Amendment of these waters with nitrate gave therefore only partial reduction. More nitrate was reduced when 2% (v/v) oil was added, with light oil giving more reduction than heavy oil. GC-MS analysis of in vitro degraded oils and electron balance considerations indicated that toluene served as the primary electron donor for nitrate reduction. The differences in the extent of nitrate reduction were thus related to the toluene content of the light and heavy oil (30 and 5 mM, respectively). Reduction of nitrate with sulfide by SO-NRB always preceded that with oil organics by hNRB, even though microbially catalyzed kinetics with either electron donor were similar. Inhibition of hNRB by sulfide is responsible for this phenomenon. Injected nitrate will thus initially be reduced with sulfide through the action of SO-NRB. However, once sulfide has been eliminated from the near-injection wellbore region, oil organics will be targeted by the action of hNRB. Hence, despite the kinetic advantage of SO-NRB, the nitrate dose required to eliminate sulfide from a reservoir depends on the concentration of hNRB-degradable oil organics, with toluene being the most important in the field under study. Because the toluene concentration is lower in heavy oilthan in light oil, nitrate injection into a heavy-oil-producing field of

USE OF POLYMERS TO RECOVER VISCOUS OIL FROM UNCONVENTIONAL RESERVOIRS

Energy Technology Data Exchange (ETDEWEB)

Randall Seright

2011-09-30

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

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

International Nuclear Information System (INIS)

Schalenbach, S.S.

1993-10-01

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

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...

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

International Nuclear Information System (INIS)

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

1991-01-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-06-30

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

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

Energy Technology Data Exchange (ETDEWEB)

Norman R. Morrow

2004-05-01

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

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

Energy Technology Data Exchange (ETDEWEB)

Norman R. Morrow

2004-07-01

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

The Influence of CO2 Solubility in Brine on Simulation of CO2 Injection into Water Flooded Reservoir and CO2 WAG

DEFF Research Database (Denmark)

Yan, Wei; Stenby, Erling Halfdan

2010-01-01

Injection of CO2 into depleted oil reservoirs is not only a traditional way to enhance oil recovery but also a relatively cheaper way to sequester CO2 underground since the increased oil production can offset some sequestration cost. CO2 injection process is often applied to water flooded...... simulations were made for seven oil samples within a wide range of temperature, pressure and salinity. The results were analyzed in terms of the change in oil recovery due to different phase equilibrium descriptions, the delay in breakthrough and the CO2 lost to the aqueous phase. The influence of different...

Modeling of CO2 migration injected in Weyburn oil reservoir

International Nuclear Information System (INIS)

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

2008-01-01

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

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

International Nuclear Information System (INIS)

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

2014-01-01

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

Artificial Neural Network Model for Alkali-Surfactant-Polymer Flooding in Viscous Oil Reservoirs: Generation and Application

Directory of Open Access Journals (Sweden)

Si Le Van

2016-12-01

Full Text Available Chemical flooding has been widely utilized to recover a large portion of the oil remaining in light and viscous oil reservoirs after the primary and secondary production processes. As core-flood tests and reservoir simulations take time to accurately estimate the recovery performances as well as analyzing the feasibility of an injection project, it is necessary to find a powerful tool to quickly predict the results with a level of acceptable accuracy. An approach involving the use of an artificial neural network to generate a representative model for estimating the alkali-surfactant-polymer flooding performance and evaluating the economic feasibility of viscous oil reservoirs from simulation is proposed in this study. A typical chemical flooding project was referenced for this numerical study. A number of simulations have been made for training on the basis of a base case from the design of 13 parameters. After training, the network scheme generated from a ratio data set of 50%-20%-30% corresponding to the number of samples used for training-validation-testing was selected for estimation with the total coefficient of determination of 0.986 and a root mean square error of 1.63%. In terms of model application, the chemical concentration and injection strategy were optimized to maximize the net present value (NPV of the project at a specific oil price from the just created ANN model. To evaluate the feasibility of the project comprehensively in terms of market variations, a range of oil prices from 30 $/bbl to 60 $/bbl referenced from a real market situation was considered in conjunction with its probability following a statistical distribution on the NPV computation. Feasibility analysis of the optimal chemical injection scheme revealed a variation of profit from 0.42 $MM to 1.0 $MM, corresponding to the changes in oil price. In particular, at the highest possible oil prices, the project can earn approximately 0.61 $MM to 0.87 $MM for a quarter

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.

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

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

Advantageous Reservoir Characterization Technology in Extra Low Permeability Oil Reservoirs

Directory of Open Access Journals (Sweden)

Yutian Luo

2017-01-01

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

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

Science.gov (United States)

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

2017-05-01

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

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.

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

Energy Technology Data Exchange (ETDEWEB)

Lillie, W

1966-04-01

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

Asphaltene laboratory assessment of a heavy onshore reservoir during pressure, temperature and composition variations to predict asphaltene onset pressure

Energy Technology Data Exchange (ETDEWEB)

Bahrami, Peyman; Ahmadi, Yaser [Islamic Azad University, Tehran (Iran, Islamic Republic of); Kharrat, Riyaz [Petroleum University of Technology, Tehran (Iran, Islamic Republic of); Mahdavi, Sedigheh; James, Lesley [Memorial University of Newfoundland, Saint John' s (Canada)

2015-02-15

An Iranian heavy oil reservoir recently encountered challenges in oil production rate, and further investigation has proven that asphaltene precipitation was the root cause of this problem. In addition, CO{sub 2} gas injection could be an appropriate remedy to enhance the production of heavy crudes. In this study, high pressure-high temperature asphaltene precipitation experiments were performed at different temperatures and pressures to investigate the asphaltene phase behavior during the natural depletion process and CO{sub 2} gas injection. Compositional modeling of experimental data predicted onset points at different temperatures which determine the zone of maximum probability of asphaltene precipitation for the studied heavy oil reservoir. Also, the effect of CO{sub 2} gas injection was investigated as a function of CO{sub 2} concentration and pressure. It was found that a CO{sub 2}-oil ratio of 40% is the optimum for limiting precipitation to have the least formation damage and surface instrument contamination.

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

Directory of Open Access Journals (Sweden)

А. Д. Алексеев

2017-12-01

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

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

Cost Effective Surfactant Formulations for Improved Oil Recovery in Carbonate Reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2007-09-30

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

Development and operation of Northern Natural's aquifer gas storage reservoirs

Energy Technology Data Exchange (ETDEWEB)

Martinson, E V

1969-01-01

There are no depleted (or nondepleted) oil and gas fields in Northern Natural Gas Co.'s market area. Consequently, when the search was started for a possible underground field, the company had to resort to the possibility of locating a water-filled, porous-rock formation (aquifer) in a geological structure which would form a suitable trap for gas storage. Geological research and exploratory drilling was carried on in S. Minnesota, E. Nebraska, and W.-central Iowa. An area located about 40 miles northwest of Des Moines, Iowa, near Redfield, appeared to have the most desirable characteristics for development of a gas-storage field. Drilling of deep developmental wells was started in late 1953 on a double- plunging anticline. The geological structure is similar to that of many oil and gas fields, but the porous formations contained only fresh water. To date, 2 major reservoirs and a minor reservoir have been developed in this structure. As much as 120 billion cu ft has been stored in the 3 reservoirs which supplied 43 billion cu ft gas withdrawals this past season from a total of 85 wells. A second aquifer gas-storage field is under development in N.-central Iowa about 15 miles northeast of Ft. Dodge.

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

Science.gov (United States)

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

2017-10-01

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

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

DEFF Research Database (Denmark)

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

2017-01-01

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

Genome-Resolved Metagenomic Analysis Reveals Roles for Candidate Phyla and Other Microbial Community Members in Biogeochemical Transformations in Oil Reservoirs.

Science.gov (United States)

Hu, Ping; Tom, Lauren; Singh, Andrea; Thomas, Brian C; Baker, Brett J; Piceno, Yvette M; Andersen, Gary L; Banfield, Jillian F

2016-01-19

Oil reservoirs are major sites of methane production and carbon turnover, processes with significant impacts on energy resources and global biogeochemical cycles. We applied a cultivation-independent genomic approach to define microbial community membership and predict roles for specific organisms in biogeochemical transformations in Alaska North Slope oil fields. Produced water samples were collected from six locations between 1,128 m (24 to 27°C) and 2,743 m (80 to 83°C) below the surface. Microbial community complexity decreased with increasing temperature, and the potential to degrade hydrocarbon compounds was most prevalent in the lower-temperature reservoirs. Sulfate availability, rather than sulfate reduction potential, seems to be the limiting factor for sulfide production in some of the reservoirs under investigation. Most microorganisms in the intermediate- and higher-temperature samples were related to previously studied methanogenic and nonmethanogenic archaea and thermophilic bacteria, but one candidate phylum bacterium, a member of the Acetothermia (OP1), was present in Kuparuk sample K3. The greatest numbers of candidate phyla were recovered from the mesothermic reservoir samples SB1 and SB2. We reconstructed a nearly complete genome for an organism from the candidate phylum Parcubacteria (OD1) that was abundant in sample SB1. Consistent with prior findings for members of this lineage, the OD1 genome is small, and metabolic predictions support an obligately anaerobic, fermentation-based lifestyle. At moderate abundance in samples SB1 and SB2 were members of bacteria from other candidate phyla, including Microgenomates (OP11), Atribacteria (OP9), candidate phyla TA06 and WS6, and Marinimicrobia (SAR406). The results presented here elucidate potential roles of organisms in oil reservoir biological processes. The activities of microorganisms in oil reservoirs impact petroleum resource quality and the global carbon cycle. We show that bacteria

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

Energy Technology Data Exchange (ETDEWEB)

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

2013-08-01

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

Different Diversity and Distribution of Archaeal Community in the Aqueous and Oil Phases of Production Fluid From High-Temperature Petroleum Reservoirs

Directory of Open Access Journals (Sweden)

Bo Liang

2018-04-01

Full Text Available To get a better knowledge on how archaeal communities differ between the oil and aqueous phases and whether environmental factors promote substantial differences on microbial distributions among production wells, we analyzed archaeal communities in oil and aqueous phases from four high-temperature petroleum reservoirs (55–65°C by using 16S rRNA gene based 454 pyrosequencing. Obvious dissimilarity of the archaeal composition between aqueous and oil phases in each independent production wells was observed, especially in production wells with higher water cut, and diversity in the oil phase was much higher than that in the corresponding aqueous phase. Statistical analysis further showed that archaeal communities in oil phases from different petroleum reservoirs tended to be more similar, but those in aqueous phases were the opposite. In the high-temperature ecosystems, temperature as an environmental factor could have significantly affected archaeal distribution, and archaeal diversity raised with the increase of temperature (p < 0.05. Our results suggest that to get a comprehensive understanding of petroleum reservoirs microbial information both in aqueous and oil phases should be taken into consideration. The microscopic habitats of oil phase, technically the dispersed minuscule water droplets in the oil could be a better habitat that containing the indigenous microorganisms.

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

Directory of Open Access Journals (Sweden)

Si Le Van

2016-09-01

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

Origin and evolution of formation water at the Jujo-Tecominoacan oil reservoir, Gulf of Mexico. Part 1: Chemical evolution and water-rock interaction

Energy Technology Data Exchange (ETDEWEB)

Birkle, Peter, E-mail: birkle@iie.org.mx [Instituto de Investigaciones Electricas (IIE), Gerencia de Geotermia, Av. Reforma 113, Cuernavaca, Morelos 62490 (Mexico); Garcia, Bernardo Martinez; Milland Padron, Carlos M. [PEMEX Exploracion y Produccion, Region Sur, Activo Integral Bellota-Jujo, Diseno de Explotacion, Cardenas, Tabasco (Mexico)

2009-04-15

The origin and evolution of formation water from Upper Jurassic to Upper Cretaceous mudstone-packstone-dolomite host rocks at the Jujo-Tecominoacan oil reservoir, located onshore in SE-Mexico at a depth from 5200 to 6200 m.b.s.l., have been investigated, using detailed water geochemistry from 12 producer wells and six closed wells, and related host rock mineralogy. Saline waters of Cl-Na type with total dissolved solids from 10 to 23 g/L are chemically distinct from hypersaline Cl-Ca-Na and Cl-Na-Ca type waters with TDS between 181 and 385 g/L. Bromine/Cl and Br/Na ratios suggest the subaerial evaporation of seawater beyond halite precipitation to explain the extreme hypersaline components, while less saline samples were formed by mixing of high salinity end members with surface-derived, low salinity water components. The dissolution of evaporites from adjacent salt domes has little impact on present formation water composition. Geochemical simulations with Harvie-M{phi}ller-Weare and PHRQPITZ thermodynamic data sets suggest secondary fluid enrichment in Ca, HCO{sub 3} and Sr by water-rock interaction. The volumetric mass balance between Ca enrichment and Mg depletion confirms dolomitization as the major alteration process. Potassium/Cl ratios below evaporation trajectory are attributed to minor precipitation of K feldspar and illitization without evidence for albitization at the Jujo-Tecominoacan reservoir. The abundance of secondary dolomite, illite and pyrite in drilling cores from reservoir host rock reconfirms the observed water-rock exchange processes. Sulfate concentrations are controlled by anhydrite solubility as indicated by positive SI-values, although anhydrite deposition is limited throughout the lithological reservoir column. The chemical variety of produced water at the Jujo-Tecominoacan oil field is related to a sequence of primary and secondary processes, including infiltration of evaporated seawater and original meteoric fluids, the subsequent

Origin and evolution of formation water at the Jujo-Tecominoacan oil reservoir, Gulf of Mexico. Part 1: Chemical evolution and water-rock interaction

International Nuclear Information System (INIS)

Birkle, Peter; Garcia, Bernardo Martinez; Milland Padron, Carlos M.

2009-01-01

The origin and evolution of formation water from Upper Jurassic to Upper Cretaceous mudstone-packstone-dolomite host rocks at the Jujo-Tecominoacan oil reservoir, located onshore in SE-Mexico at a depth from 5200 to 6200 m.b.s.l., have been investigated, using detailed water geochemistry from 12 producer wells and six closed wells, and related host rock mineralogy. Saline waters of Cl-Na type with total dissolved solids from 10 to 23 g/L are chemically distinct from hypersaline Cl-Ca-Na and Cl-Na-Ca type waters with TDS between 181 and 385 g/L. Bromine/Cl and Br/Na ratios suggest the subaerial evaporation of seawater beyond halite precipitation to explain the extreme hypersaline components, while less saline samples were formed by mixing of high salinity end members with surface-derived, low salinity water components. The dissolution of evaporites from adjacent salt domes has little impact on present formation water composition. Geochemical simulations with Harvie-Mφller-Weare and PHRQPITZ thermodynamic data sets suggest secondary fluid enrichment in Ca, HCO 3 and Sr by water-rock interaction. The volumetric mass balance between Ca enrichment and Mg depletion confirms dolomitization as the major alteration process. Potassium/Cl ratios below evaporation trajectory are attributed to minor precipitation of K feldspar and illitization without evidence for albitization at the Jujo-Tecominoacan reservoir. The abundance of secondary dolomite, illite and pyrite in drilling cores from reservoir host rock reconfirms the observed water-rock exchange processes. Sulfate concentrations are controlled by anhydrite solubility as indicated by positive SI-values, although anhydrite deposition is limited throughout the lithological reservoir column. The chemical variety of produced water at the Jujo-Tecominoacan oil field is related to a sequence of primary and secondary processes, including infiltration of evaporated seawater and original meteoric fluids, the subsequent mixing of

Numerical Simulation Study on Steam-Assisted Gravity Drainage Performance in a Heavy Oil Reservoir with a Bottom Water Zone

Directory of Open Access Journals (Sweden)

Jun Ni

2017-12-01

Full Text Available In the Pikes Peak oil field near Lloydminster, Canada, a significant amount of heavy oil reserves is located in reservoirs with a bottom water zone. The properties of the bottom water zone and the operation parameters significantly affect oil production performance via the steam-assisted gravity drainage (SAGD process. Thus, in order to develop this type of heavy oil resource, a full understanding of the effects of these properties is necessary. In this study, the numerical simulation approach was applied to study the effects of properties in the bottom water zone in the SAGD process, such as the initial gas oil ratio, the thickness of the reservoir, and oil saturation of the bottom water zone. In addition, some operation parameters were studied including the injection pressure, the SAGD well pair location, and five different well patterns: (1 two corner wells, (2 triple wells, (3 downhole water sink well, (4 vertical injectors with a horizontal producer, and (5 fishbone well. The numerical simulation results suggest that the properties of the bottom water zone affect production performance extremely. First, both positive and negative effects were observed when solution gas exists in the heavy oil. Second, a logarithmical relationship was investigated between the bottom water production ratio and the thickness of the bottom water zone. Third, a non-linear relation was obtained between the oil recovery factor and oil saturation in the bottom water zone, and a peak oil recovery was achieved at the oil saturation rate of 30% in the bottom water zone. Furthermore, the operation parameters affected the heavy oil production performance. Comparison of the well patterns showed that the two corner wells and the triple wells patterns obtained the highest oil recovery factors of 74.71% and 77.19%, respectively, which are almost twice the oil recovery factors gained in the conventional SAGD process (47.84%. This indicates that the optimized SAGD process

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

Science.gov (United States)

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

2018-06-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2010-07-01

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

Nagylengyel: an interesting reservoir. [Yugoslovia

Energy Technology Data Exchange (ETDEWEB)

Dedinszky, J

1971-04-01

The Nagylengyel oil field, discovered in 1951, has oil-producing formations mostly in the Upper-Triassic dolomites, in the Norian-Ractian transition formations, in the Upper-Cretaceous limestones and shales, and in the Miocene. The formation of the reservoir space occurred in many stages. A porous, cavernous fractured reservoir is developed in the Norian principal dolomite. A cavernous fractured reservoir exists in the Cretaceous limestone and in the Cretaceous shale and porous fractured reservoir is developed in the Miocene. The derivation of the model of the reservoir, and the conservative evaluation of the volume of the reservoir made it possible to use secondary recovery.

Study of the Effect of Clay Particles on Low Salinity Water Injection in Sandstone Reservoirs

Directory of Open Access Journals (Sweden)

Sina Rezaei Gomari

2017-03-01

Full Text Available The need for optimal recovery of crude oil from sandstone and carbonate reservoirs around the world has never been greater for the petroleum industry. Water-flooding has been applied to the supplement primary depletion process or as a separate secondary recovery method. Low salinity water injection is a relatively new method that involves injecting low salinity brines at high pressure similar to conventional water-flooding techniques, in order to recover crude oil. The effectiveness of low salinity water injection in sandstone reservoirs depends on a number of parameters such as reservoir temperature, pressure, type of clay particle and salinity of injected brine. Clay particles present on reservoir rock surfaces adsorb polar components of oil and modify wettability of sandstone rocks to the oil-wet state, which is accountable for the reduced recovery rates by conventional water-flooding. The extent of wettability alteration caused by three low salinity brines on oil-wet sandstone samples containing varying clay content (15% or 30% and type of clay (kaolinite/montmorillonite were analyzed in the laboratory experiment. Contact angles of mica powder and clay mixture (kaolinite/montmorillonite modified with crude oil were measured before and after injection with three low salinity sodium chloride brines. The effect of temperature was also analyzed for each sample. The results of the experiment indicate that samples with kaolinite clay tend to produce higher contact angles than samples with montmorillonite clay when modified with crude oil. The highest degree or extent of wettability alteration from oil-wet to intermediate-wet state upon injection with low salinity brines was observed for samples injected with brine having salinity concentration of 2000 ppm. The increase in temperature tends to produce contact angles values lying in the higher end of the intermediate-wet range (75°–115° for samples treated at 50 °C, while their corresponding

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

Science.gov (United States)

Schiltz, Kelsey Kristine

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

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

Science.gov (United States)

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

2011-01-01

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

Reactive Transport Modeling of Microbe-mediated Fe (II) Oxidation for Enhanced Oil Recovery

Science.gov (United States)

Surasani, V.; Li, L.

2011-12-01

Microbially Enhanced Oil Recovery (MEOR) aims to improve the recovery of entrapped heavy oil in depleted reservoirs using microbe-based technology. Reservoir ecosystems often contain diverse microbial communities those can interact with subsurface fluids and minerals through a network of nutrients and energy fluxes. Microbe-mediated reactions products include gases, biosurfactants, biopolymers those can alter the properties of oil and interfacial interactions between oil, brine, and rocks. In addition, the produced biomass and mineral precipitates can change the reservoir permeability profile and increase sweeping efficiency. Under subsurface conditions, the injection of nitrate and Fe (II) as the electron acceptor and donor allows bacteria to grow. The reaction products include minerals such as Fe(OH)3 and nitrogen containing gases. These reaction products can have large impact on oil and reservoir properties and can enhance the recovery of trapped oil. This work aims to understand the Fe(II) oxidation by nitrate under conditions relevant to MEOR. Reactive transport modeling is used to simulate the fluid flow, transport, and reactions involved in this process. Here we developed a complex reactive network for microbial mediated nitrate-dependent Fe (II) oxidation that involves both thermodynamic controlled aqueous reactions and kinetic controlled Fe (II) mineral reaction. Reactive transport modeling is used to understand and quantify the coupling between flow, transport, and reaction processes. Our results identify key parameter controls those are important for the alteration of permeability profile under field conditions.

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

Science.gov (United States)

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

2010-05-01

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

Eos modeling and reservoir simulation study of bakken gas injection improved oil recovery in the elm coulee field, Montana

Science.gov (United States)

Pu, Wanli

The Bakken Formation in the Williston Basin is one of the most productive liquid-rich unconventional plays. The Bakken Formation is divided into three members, and the Middle Bakken Member is the primary target for horizontal wellbore landing and hydraulic fracturing because of its better rock properties. Even with this new technology, the primary recovery factor is believed to be only around 10%. This study is to evaluate various gas injection EOR methods to try to improve on that low recovery factor of 10%. In this study, the Elm Coulee Oil Field in the Williston Basin was selected as the area of interest. Static reservoir models featuring the rock property heterogeneity of the Middle Bakken Member were built, and fluid property models were built based on Bakken reservoir fluid sample PVT data. By employing both compositional model simulation and Todd-Longstaff solvent model simulation methods, miscible gas injections were simulated and the simulations speculated that oil recovery increased by 10% to 20% of OOIP in 30 years. The compositional simulations yielded lower oil recovery compared to the solvent model simulations. Compared to the homogeneous model, the reservoir model featuring rock property heterogeneity in the vertical direction resulted in slightly better oil recovery, but with earlier CO2 break-through and larger CO2 production, suggesting that rock property heterogeneity is an important property for modeling because it has a big effect on the simulation results. Long hydraulic fractures shortened CO2 break-through time greatly and increased CO 2 production. Water-alternating-gas injection schemes and injection-alternating-shut-in schemes can provide more options for gas injection EOR projects, especially for gas production management. Compared to CO2 injection, separator gas injection yielded slightly better oil recovery, meaning separator gas could be a good candidate for gas injection EOR; lean gas generated the worst results. Reservoir

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

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.

Water in chalk reservoirs: 'friend or foe?'

International Nuclear Information System (INIS)

Hjuler, Morten Leth

2004-01-01

Most of the petroleum fields in the Norwegian sector of the North Sea are sandstone reservoirs; the oil and gas are trapped in different species of sandstone. But the Ekofisk Field is a chalk reservoir, which really challenges the operator companies. When oil is produced from chalk reservoirs, water usually gets in and the reservoir subsides. The subsidence may be expensive for the oil companies or be used to advantage by increasing the recovery rate. Since 60 per cent of the world's petroleum reserves are located in carbonate reservoirs, it is important to understand what happens as oil and gas are pumped out. Comprehensive studies at the Department of Petroleum Technology and Applied Geophysics at Stavanger University College in Norway show that the mechanical properties of chalk are considerably altered when the pores in the rock become saturated with oil/gas or water under different stress conditions. The processes are extremely complex. The article also maintains that the effects of injecting carbon dioxide from gas power plants into petroleum reservoirs should be carefully studied before this is done extensively

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

The end of cheap oil

International Nuclear Information System (INIS)

Zagar, J.J.; Campbell, C.J.

1999-01-01

Easy to find 'conventional' oil in huge quantities has fueled and satisfied the World's thirst for energy this century. About 95% of all oil produced-and 90% of today's production---comes from this group of hydrocarbons. But the coming century of the new millennium will see the exit of conventional oil as a major player on the World's energy stage. Already, outside the Middle East, conventional oil production is on the decline. And the Middle East with its vast reservoirs of oil will soon reach the mid-point of depletion and begin its irreversible decline. Currently, one barrel of oil is being found for every four barrels that are produced. The Middle East now supplies 30% of the World's conventional oil production and that trend is rising because, unlike in the 1970s, no new major provinces, save perhaps the Caspian, are there to deliver flush production. The stage is now set for another 'energy crisis' starting with higher prices from Middle East control and followed by the onset of physical shortage around 2010. We face something new to human experience. (author)

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

Energy Technology Data Exchange (ETDEWEB)

Bou-Mikael, Sami

2002-02-05

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

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

Science.gov (United States)

2010-07-01

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

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.

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

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.

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 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).

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

Directory of Open Access Journals (Sweden)

Jinzhi Zhu

2017-07-01

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

Volume 5: An evaluation of known remaining oil resources in piercement salt dome reservoirs in the Gulf of Mexico

Energy Technology Data Exchange (ETDEWEB)

Mohan, H.; Rogers, M.; Becker, A.; Biglarbigi, K.; Brashear, J. [ICF Kaiser-ICF Information Technology, Inc., Fairfax, VA (United States)

1996-08-01

The US Department of Energy, Office of Fossil Energy (DOE/FE) has among its missions the facilitation of the development of required technologies to maximize the potential economic recovery of domestic oil and gas resources--both offshore and onshore, especially from Federal lands. In planning its activities, the DOE/FE relies on a number of comprehensive analytical systems in order to target and prioritize its research and development (R and D) activities and to estimate the benefits of its programs. DOE/FE`s analytical system, however, lacks the capability to assess the potential of future technology advances on the exploration, development, and production of crude oil resources in the Federal offshore of the Gulf of Mexico. The objective of the present effort is to develop an analytical system to characterize a portion of the Gulf offshore resources--the remaining unrecovered mobile oil resource associated with piercement salt dome reservoirs (hereafter referred to as salt dome reservoirs), and to evaluate additional recovery potential and related economic benefits that could result from the application of improved technologies. As part of the present effort a comprehensive analytical system has been developed for the characterization and evaluation of unrecovered mobile oil associated with the salt dome reservoirs in Federal offshore Gulf of Mexico. The system consists of a comprehensive database containing detailed rock and fluid properties, geologic information, and production and development history for 1,289 major fields and reservoirs representing an estimated 60% of the salt dome resources in the region. In addition, two separate methodologies and related economic and predictive models have been developed for the evaluation of applicable recovery processes. The system is intended for use as part of DOE`s Tertiary Oil Recovery Information System (TORIS).

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

NARCIS (Netherlands)

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

2017-01-01

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

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

KAUST Repository

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

2014-01-01

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

Development Optimization and Uncertainty Analysis Methods for Oil and Gas Reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2017-04-15

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

Development Optimization and Uncertainty Analysis Methods for Oil and Gas Reservoirs

International Nuclear Information System (INIS)

Ettehadtavakkol, Amin; Jablonowski, Christopher; Lake, Larry

2017-01-01

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

26 CFR 1.611-1 - Allowance of deduction for depletion.

Science.gov (United States)

2010-04-01

... 26 Internal Revenue 7 2010-04-01 2010-04-01 true Allowance of deduction for depletion. 1.611-1... depletion. (a) Depletion of mines, oil and gas wells, other natural deposits, and timber—(1) In general... mines, oil and gas wells, other natural deposits, and timber, a reasonable allowance for depletion. In...

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

OpenAIRE

Yang, Yichen

2016-01-01

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

Bazhen Fm matured reservoir evaluation (West Siberia, Russia)

Science.gov (United States)

Parnachev, S.; Skripkin, A.; Baranov, V.; Zakharov, S.

2015-02-01

The depletion of the traditional sources of hydrocarbons leads to the situation when the biggest players of the oil and gas production market turn to unconventional reserves. Commercial shale oil and gas production levels in the USA have largely determined world prospects for oil and gas industry development. Russia takes one of the leading place in the world in terms of shale oil resources. The main source rock of the West Siberia, the biggest oil and gas basin in Russia under development, the Bazhen Fm and its stratigraphic and lithologic analogs, is located in the territory of over 1,000,000 square kilometers. Provided it has similar key properties (organic carbon content, porosity, permeability) with the deposits of the Bakken Fm and Green River Fm, USA, it is still extremely poorly described with laboratory methods. We have performed the laboratory analysis of core samples from a well drilled in Bazhen Fm deposits with matured organic matter (Tmax>435 °C). It was demonstrated the applicability of the improved steady-state gas flow method to evaluate the permeability of nanopermeable rocks. The role of natural fracturing in forming voids was determided that allows regarding potential Bazhen Fm reservoirs as systems with dual porosity and dual permeability.

Bazhen Fm matured reservoir evaluation (West Siberia, Russia)

International Nuclear Information System (INIS)

Parnachev, S; Skripkin, A; Baranov, V; Zakharov, S

2015-01-01

The depletion of the traditional sources of hydrocarbons leads to the situation when the biggest players of the oil and gas production market turn to unconventional reserves. Commercial shale oil and gas production levels in the USA have largely determined world prospects for oil and gas industry development. Russia takes one of the leading place in the world in terms of shale oil resources. The main source rock of the West Siberia, the biggest oil and gas basin in Russia under development, the Bazhen Fm and its stratigraphic and lithologic analogs, is located in the territory of over 1,000,000 square kilometers. Provided it has similar key properties (organic carbon content, porosity, permeability) with the deposits of the Bakken Fm and Green River Fm, USA, it is still extremely poorly described with laboratory methods. We have performed the laboratory analysis of core samples from a well drilled in Bazhen Fm deposits with matured organic matter (T max >435 °C). It was demonstrated the applicability of the improved steady-state gas flow method to evaluate the permeability of nanopermeable rocks. The role of natural fracturing in forming voids was determided that allows regarding potential Bazhen Fm reservoirs as systems with dual porosity and dual permeability

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

Energy Technology Data Exchange (ETDEWEB)

1991-12-31

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

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

Capital expenditure and depletion

International Nuclear Information System (INIS)

Rech, O.; Saniere, A.

2003-01-01

In the future, the increase in oil demand will be covered for the most part by non conventional oils, but conventional sources will continue to represent a preponderant share of the world oil supply. Their depletion represents a complex challenge involving technological, economic and political factors. At the same time, there is reason for concern about the decrease in exploration budgets at the major oil companies. (author)

Capital expenditure and depletion

Energy Technology Data Exchange (ETDEWEB)

Rech, O.; Saniere, A

2003-07-01

In the future, the increase in oil demand will be covered for the most part by non conventional oils, but conventional sources will continue to represent a preponderant share of the world oil supply. Their depletion represents a complex challenge involving technological, economic and political factors. At the same time, there is reason for concern about the decrease in exploration budgets at the major oil companies. (author)

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

Science.gov (United States)

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

2002-05-01

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

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...

Nonlinear Model Predictive Control for Oil Reservoirs Management

DEFF Research Database (Denmark)

Capolei, Andrea

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

The Galeta oil spill: Pt. 4

International Nuclear Information System (INIS)

Burns, K.A.; Yelle-Simmons, L.

1994-01-01

This paper gives the detailed compositions of oil residues in sediments and encrusting bivalves, and the changes over time. Initial weathering processes removed most of the volatile hydrocarbons and all market alkanes in oil adsorbed to surface sediments within 6 months after the spill. This initially fast rate of biodegradation was not maintained in the rate of disappearance of the aromatic hydrocarbons over time. Oil leaching out of heavily contaminated sediments was bioaccumulated in bivalves for at least 5 years. The organisms accumulated the whole range of alkylated polynuclear aromatic hydrocarbons (PAHs) in the naphthalene through the benzoperylene elution range, seemingly in proportion to what was leached from sediments. A change in the composition of the aromatics bioaccumulated at most sites in year 5 indicated depletion of the most soluble and most acutely toxic hydrocarbons in the readily leachable reservoirs. (author)

How Specific Microbial Communities Benefit the Oil Industry: Case Study - Proof of Concept that Oil Entrained in Marginal Reservoirs Can Be Bioconverted to Methane Gas as a Green Energy Recovery Strategy

Science.gov (United States)

Gieg, Lisa

Conventional oil recovery techniques such as water flooding typically remove only up to 40% of the oil present in reservoirs. Enhanced oil recovery (EOR) techniques are considered tertiary strategies that may be applied to recover a greater volume of oil. In particular, the use of microorganisms to aid in oil production (microbial-enhanced oil recovery or MEOR) is considered a green energy recovery strategy since microbial processes do not require large amounts of energy input and can potentially produce large amounts of useful byproducts from inexpensive and renewable resources (Youssef et al., 2008). These byproducts can include the generation of biosurfactants, emulsifiers, acids, alcohols, and/or gases that can serve as agents for oil recovery. Recent reviews have summarised MEOR efforts undertaken since the 1950's with varying degrees of success (e.g. Jack, 1993; Belyaev et al., 2004; McInerney et al., 2005; Youssef et al., 2008). In MEOR schemes, petroleum reservoirs may be either stimulated with nutrients or inoculated with microorganisms with known activity to achieve desired effects (Youssef et al., 2008).

Application of Reservoir Characterization and Advanced Technology to Improve Recovery and Economics in a Lower Quality Shallow Shelf Carbonate Reservoir

International Nuclear Information System (INIS)

Hickman, Scott T.; Justice James L.; Taylor, Archie R.

1999-01-01

The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs

Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO2 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales

International Nuclear Information System (INIS)

Morea, Michael F.

1999-01-01

The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO2 enhanced oil recovery project in the Antelope Shale in Buena Vista Hills Field. The Buena Vista Hills pilot CO2 project will demonstrate the economic viability and widespread applicability of CO2 flooding in fractured siliceous shale reservoirs of the San Joaquin Valley. The research consists of four primary work processes: (1) Reservoir Matrix and Fluid Characterization; (2) Fracture characterization; (3) reservoir Modeling and Simulation; and (4) CO2 Pilot Flood and Evaluation. Work done in these areas is subdivided into two phases or budget periods. The first phase of the project will focus on the application of a variety of advanced reservoir characterization techniques to determine the production characteristics of the Antelope Shale reservoir. Reservoir models based on the results of the characterization work will be used to evaluate how the reservoir will respond to secondary recovery and EOR processes. The second phase of the project will include the implementation and evaluation of an advanced enhanced oil recovery (EOR) pilot in the United Anticline (West Dome) of the Buena Vista Hills Field

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.

Analysis of nitrogen injection as alternative fluid to steam in heavy oil reservoir; Analise da injecao de nitrogenio como fluido alternativo ao vapor em reservatorio de oleo pesado

Energy Technology Data Exchange (ETDEWEB)

Rodrigues, Marcos Allyson Felipe; Galvao, Edney Rafael Viana Pinheiro; Barillas, Jennys Lourdes; Mata, Wilson da; Dutra Junior, Tarcilio Viana [Universidade Federal do Rio Grande do Norte (UFRN), RN (Brazil)

2012-07-01

Many of hydrocarbon reserves existing in the world are formed by heavy oils (deg API between 10 and 20). Moreover, several heavy oil fields are mature and, thus, offer great challenges for oil industry. Among the thermal methods used to recover these resources, steam flooding has been the main economically viable alternative. Latent heat carried by steam heats the reservoir, reducing oil viscosity and facilitating the production. This method has many variations and has been studied both theoretically and experimentally (in pilot projects and in full field applications). In order to increase oil recovery and reduce steam injection costs, the injection of alternative fluid has been used on three main ways: alternately, co-injected with steam and after steam injection interruption. The main objective of these injection systems is to reduce the amount of heat supplied to the reservoir, using cheaper fluids and maintaining the same oil production levels. In this paper, the use of N{sub 2} as an alternative fluid to the steam was investigated. The analyzed parameters were oil recoveries and net cumulative oil productions. The reservoir simulation model corresponds to an oil reservoir of 100 m x 100 m x 28 m size, on a Cartesian coordinates system (x, y and z directions). It is a semi synthetic model with some reservoir data similar to those found in Potiguar Basin, Brazil. All studied cases were done using the simulator STARS from CMG (Computer Modelling Group, version 2009.10). It was found that N{sub 2} injection after steam injection interruption achieved the highest net cumulative oil compared to others injection system. Moreover, it was observed that N2 as alternative fluid to steam did not present increase on oil recovery. (author)

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

Energy Technology Data Exchange (ETDEWEB)

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

1996-02-01

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

Evaluation of miscible and immiscible CO2 injection in one of the Iranian oil fields

Directory of Open Access Journals (Sweden)

Aref Hashemi Fath

2014-09-01

Full Text Available Carbon dioxide (CO2 flooding is one of the most important methods for enhanced oil recovery (EOR because it not only increases oil recovery efficiency but also causes a reduction of greenhouse gas emissions. It is a very complex system, involving phase behavior that could increase the recovery of oil by means of swelling, evaporation and decreasing viscosity of the oil. In this study, a reservoir modeling approach was used to evaluate immiscible and miscible CO2 flooding in a fractured oil field. To reduce simulation time, we grouped fluid components into 10 pseudo-components. The 3-parameter, Peng–Robinson Equation of State (EOS was used to match PVT experimental data by using the PVTi software. A one-dimensional slim-tube model was defined using ECLIPSE 300 software to determine the minimum miscibility pressure (MMP for injection of CO2. We used FloGrid software for making a reservoir static model and the reservoir model was calibrated using manual and assisted history matching methods. Then various scenarios of natural depletion, immiscible and miscible CO2 injection have been simulated by ECLIPSE 300 software and then the simulation results of scenarios have been compared. Investigation of simulation results shows that the oil recovery factor in miscible CO2 injection scenario is more than other methods.

Earthquakes and depleted gas reservoirs: which comes first?

Science.gov (United States)

Mucciarelli, M.; Donda, F.; Valensise, G.

2015-10-01

While scientists are paying increasing attention to the seismicity potentially induced by hydrocarbon exploitation, so far, little is known about the reverse problem, i.e. the impact of active faulting and earthquakes on hydrocarbon reservoirs. The 20 and 29 May 2012 earthquakes in Emilia, northern Italy (Mw 6.1 and 6.0), raised concerns among the public for being possibly human-induced, but also shed light on the possible use of gas wells as a marker of the seismogenic potential of an active fold and thrust belt. We compared the location, depth and production history of 455 gas wells drilled along the Ferrara-Romagna arc, a large hydrocarbon reserve in the southeastern Po Plain (northern Italy), with the location of the inferred surface projection of the causative faults of the 2012 Emilia earthquakes and of two pre-instrumental damaging earthquakes. We found that these earthquake sources fall within a cluster of sterile wells, surrounded by productive wells at a few kilometres' distance. Since the geology of the productive and sterile areas is quite similar, we suggest that past earthquakes caused the loss of all natural gas from the potential reservoirs lying above their causative faults. To validate our hypothesis we performed two different statistical tests (binomial and Monte Carlo) on the relative distribution of productive and sterile wells, with respect to seismogenic faults. Our findings have important practical implications: (1) they may allow major seismogenic sources to be singled out within large active thrust systems; (2) they suggest that reservoirs hosted in smaller anticlines are more likely to be intact; and (3) they also suggest that in order to minimize the hazard of triggering significant earthquakes, all new gas storage facilities should use exploited reservoirs rather than sterile hydrocarbon traps or aquifers.

Tailor-made surfactants for optimized chemical EOR. Meeting oil reservoir conditions by applied knowledge of structure-performance relationship in extended surfactants

Energy Technology Data Exchange (ETDEWEB)

Trahan, G.; Sorensen, W. [Sasol North America Inc., Westlake, LA (United States); Jakobs-Sauter, B. [Sasol Germany GmbH (Germany)

2013-08-01

Formulating the surfactant package for chemical EOR is a time consuming and expensive process - the formulation needs to fit the specific reservoir conditions (like oil type, temperature, salinity, etc.) to give optimum performance and the number of formulation variables is virtually endless. This paper studies the impact of surfactant structure on EOR formulation ability and performance and how to adjust the structure of the surfactant molecule to meet a specific reservoir's needs. Data from salinity phase boundary studies of alcohol propoxy sulfates illustrate how changes in alcohol structure as well as in propylene oxide level can shift optimum salinity and temperature to the desired range in a given model oil. From these data the impact of individual structural units was evaluated. Application of the HLD model (Hydrophilic-Lipophilic Deviation) shows how to extrapolate from the known data set to actual reservoir conditions. This is illustrated by studies on crude oil samples. Additional tests study how effective the selected surfactants perform. The HLD concept proves to be a valuable tool to select and tailor surfactants to individual reservoir needs, thus simplifying the surfactant screening process for EOR formulations by pre-selection of suitable structures and ultimately reducing cost and effort on the way to the most effective chemical EOR package. (orig.)

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

Science.gov (United States)

Wang, Zhenjun; Huang, Jiehao

2018-04-01

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

Using combinations of methods for evaluating capacity of fissured reservoirs of the upper Cretaceous Malgobek- Voznesensk oil deposit in Ch. I. ASSR

Energy Technology Data Exchange (ETDEWEB)

Vasilev, V.M.

1968-01-01

Ch.I.ASSR stands for the Chechen-Ingush Autonomous Soviet Socialist Republic (North Caucasus). The deposit is associated with practically impervious limestones (less than 1 md) with intergranular porosity; oil is found along fractures of various length and degree of openness. Amount of fluids contained in this type of reservoirs was evaluated by the following methods: (1) core analyses; (2) geophysical surveying of wells; (3) hydrodynamic techniques of well investigations; and (4) according to parts of the deposits where oil was already recovered. Statistical interpretation of combined data indicated that reservoir properties gradually become poorer with increasing depth and in the direction from the crest of the fold towards its flanks and periclinal ends. Application of some formulas used in this work is explained. It is concluded that by using combinations of methods it is possible to evaluate the absolute and effective values of secondary reservoir capacity and to establish approximately geological and retrievable oil reserves.

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

Directory of Open Access Journals (Sweden)

Rongwang Yin

2018-01-01

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

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

Directory of Open Access Journals (Sweden)

Yuan eXue

2015-12-01

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

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

Energy Technology Data Exchange (ETDEWEB)

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

2008-01-15

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

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.

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

Energy Technology Data Exchange (ETDEWEB)

La Pointe, Paul R.; Hermanson, Jan

2002-09-09

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

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

Energy Technology Data Exchange (ETDEWEB)

Wehner, S.C.

1995-05-01

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

PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

Energy Technology Data Exchange (ETDEWEB)

Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; William Raatz; Cari Breton; Stephen C. Ruppel; Charles Kerans; Mark H. Holtz

2003-04-01

A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest petroleum-producing basin in the US. Approximately 1300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl of oil through 2000. Of these major reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. On a preliminary basis, 32 geologic plays have been defined for Permian Basin oil reservoirs and assignment of each of the 1300 major reservoirs to a play has begun. The reservoirs are being mapped and compiled in a Geographic Information System (GIS) by play. Detailed studies of three reservoirs are in progress: Kelly-Snyder (SACROC unit) in the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play, Fullerton in the Leonardian Restricted Platform Carbonate play, and Barnhart (Ellenburger) in the Ellenburger Selectively Dolomitized Ramp Carbonate play. For each of these detailed reservoir studies, technologies for further, economically viable exploitation are being investigated.

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.

Effects of Microwave Radiation on Oil Recovery

Science.gov (United States)

Esmaeili, Abdollah

2011-12-01

A variety of oil recovery methods have been developed and applied to mature and depleted reservoirs in order to improve the efficiency. Microwave radiation oil recovery method is a relatively new method and has been of great interest in the recent years. Crude oil is typically co-mingled with suspended solids and water. To increase oil recovery, it is necessary to remove these components. The separation of oil from water and solids using gravitational settling methods is typically incomplete. Oil-in-water and oil-water-solid emulsions can be demulsified and separated into their individual layers by microwave radiation. The data also show that microwave separation is faster than gravity separation and can be faster than conventional heating at many conditions. After separation of emulsion into water and oil layers, water can be discharged and oil is collected. High-frequency microwave recycling process can recover oil and gases from oil shale, residual oil, drill cuttings, tar sands oil, contaminated dredge/sediments, tires and plastics with significantly greater yields and lower costs than are available utilizing existing known technologies. This process is environmentally friendly, fuel-generating recycler to reduce waste, cut emissions, and save energy. This paper presents a critical review of Microwave radiation method for oil recovery.

Evaluation of microbial community composition in thermophilic methane-producing incubation of production water from a high-temperature oil reservoir.

Science.gov (United States)

Zhou, Fang; Mbadinga, Serge Maurice; Liu, Jin-Feng; Gu, Ji-Dong; Mu, Bo-Zhong

2013-01-01

Investigation of petroleum microbes is fundamental for the development and utilization of oil reservoirs' microbial resources, and also provides great opportunities for research and development of bio-energy. Production water from a high-temperature oil reservoir was incubated anaerobically at 55 degrees C for more than 400 days without amendment of any nutrients. Over the time of incubation, about 1.6 mmol of methane and up to 107 micromol of hydrogen (H2) were detected in the headspace. Methane formation indicated that methanogenesis was likely the predominant process in spite of the presence of 23.4 mM SO4(2-) in the production water. Microbial community composition of the incubation was characterized by means of 16S rRNA gene clone libraries construction. Bacterial composition changed from Pseudomonales as the dominant population initially to Hydrogenophilales-related microorganisms affiliated to Petrobacter spp. closely. After 400 days of incubation, other bacterial members detected were related to Anareolineales, beta-, gamma-, and delta-Proteobacteria. The archaeal composition of the original production water was essentially composed of obligate acetoclastic methanogens of the genus Methanosaeta, but the incubation was predominantly composed of CO2-reducing methanogens of the genus Methanothermobacter and Crenarchaeotes-related microorganisms. Our results suggest that methanogenesis could be more active than expected in oil reservoir environments and methane formation from CO2-reduction played a significant role in the methanogenic community. This conclusion is consistent with the predominant role played by H2-oxidizing methanogens in the methanogenic conversion of organic matter in high-temperature petroleum reservoirs.

CO2 Huff-n-Puff process in a light oil shallow shelf carbonate reservoir. Annual report, January 1, 1995--December 31, 1995

Energy Technology Data Exchange (ETDEWEB)

Wehner, S.C.; Boomer, R.J.; Cole, R.; Preiditus, J.; Vogt, J.

1996-09-01

The application of cyclic CO{sub 2}, often referred to as the CO{sub 2} Huff-n-Puff process, may find its niche in the maturing waterfloods of the Permian Basin. Coupling the CO{sub 2} H-n-P process to miscible flooding applications could provide the needed revenue to sufficiently mitigate near-term negative cash flow concerns in the capital intensive miscible projects. Texaco Exploration & Production Inc. and the U.S. Department of Energy have teamed up in an attempt to develop the CO{sub 2} Huff-n-Puff process in the Grayburg/San Andres formation; a light oil, shallow shelf carbonate reservoir within the Permian Basin. This cost-shared effort is intended to demonstrate the viability of this underutilized technology in a specific class of domestic reservoir. A significant amount of oil reserves are located in carbonate reservoirs. Specifically, the carbonates deposited in shallow shelf (SSC) environments make up the largest percentage of known reservoirs within the Permian Basin of North America. Many of these known resources have been under waterflooding operations for decades and are at risk of abandonment if crude oil recoveries cannot be economically enhanced. The selected site for this demonstration project is the Central Vacuum Unit waterflood in Lea County, New Mexico.

The multiphase flow system used in exploiting depleted reservoirs: water-based Micro-bubble drilling fluid

International Nuclear Information System (INIS)

Zheng Lihui; He Xiaoqing; Wang Xiangchun; Fu Lixia

2009-01-01

Water-based micro-bubble drilling fluid, which is used to exploit depleted reservoirs, is a complicated multiphase flow system that is composed of gas, water, oil, polymer, surfactants and solids. The gas phase is separate from bulk water by two layers and three membranes. They are 'surface tension reducing membrane', 'high viscosity layer', 'high viscosity fixing membrane', 'compatibility enhancing membrane' and 'concentration transition layer of liner high polymer (LHP) and surfactants' from every gas phase centre to the bulk water. 'Surface tension reducing membrane', 'high viscosity layer' and 'high viscosity fixing membrane' bond closely to pack air forming 'air-bag', 'compatibility enhancing membrane' and 'concentration transition layer of LHP and surfactants' absorb outside 'air-bag' to form 'incompact zone'. From another point of view, 'air-bag' and 'incompact zone' compose micro-bubble. Dynamic changes of 'incompact zone' enable micro-bubble to exist lonely or aggregate together, and lead the whole fluid, which can wet both hydrophilic and hydrophobic surface, to possess very high viscosity at an extremely low shear rate but to possess good fluidity at a higher shear rate. When the water-based micro-bubble drilling fluid encounters leakage zones, it will automatically regulate the sizes and shapes of the bubbles according to the slot width of fracture, the height of cavern as well as the aperture of openings, or seal them by making use of high viscosity of the system at a very low shear rate. Measurements of the rheological parameters indicate that water-based micro-bubble drilling fluid has very high plastic viscosity, yield point, initial gel, final gel and high ratio of yield point and plastic viscosity. All of these properties make the multiphase flow system meet the requirements of petroleum drilling industry. Research on interface between gas and bulk water of this multiphase flow system can provide us with information of synthesizing effective

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs

Energy Technology Data Exchange (ETDEWEB)

Bjorn N. P. Paulsson

2006-09-30

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to perform high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology has been hampered by the lack of acquisition technology necessary to record large volumes of high frequency, high signal-to-noise-ratio borehole seismic data. This project took aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array has removed the technical acquisition barrier for recording the data volumes necessary to do high resolution 3D VSP and 3D cross-well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that promise to take the gas industry to the next level in their quest for higher resolution images of deep and complex oil and gas reservoirs. Today only a fraction of the oil or gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of detailed compartmentalization of oil and gas reservoirs. In this project, we developed a 400 level 3C borehole seismic receiver array that allows for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. This new array has significantly increased the efficiency of recording large data volumes at sufficiently dense spatial sampling to resolve reservoir complexities. The receiver pods have been fabricated and tested to withstand high temperature (200 C/400 F) and high pressure (25,000 psi), so that they can operate in wells up to 7,620 meters (25,000 feet) deep. The receiver array is deployed on standard production or drill tubing. In combination with 3C surface seismic or 3C borehole seismic sources, the 400

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

DEFF Research Database (Denmark)

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

2016-01-01

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

Using Polymer Alternating Gas to Enhance Oil Recovery in Heavy Oil

Science.gov (United States)

Yang, Yongzhi; Li, Weirong; Zhou, Tiyao; Dong, Zhenzhen

2018-02-01

CO2 has been used to recover oil for more than 40 years. Currently, about 43% of EOR production in U.S. is from CO2 flooding. CO2 flooding is a well-established EOR technique, but its density and viscosity nature are challenges for CO2 projects. Low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cp) leads to poor volumetric sweep efficiency. So water-alternating-gas (WAG) method was used to control the mobility of CO2 and improve sweep efficiency. However, WAG process has some other problems in heavy oil reservoir, such as poor mobility ratio and gravity overriding. To examine the applicability of carbon dioxide to recover viscous oil from highly heterogeneous reservoirs, this study suggests a new EOR method--polymer-alternating gas (PAG) process. The process involves a combination of polymer flooding and CO2 injection. To confirm the effectiveness of PAG process in heavy oils, a reservoir model from Liaohe Oilfield is used to compare the technical and economic performance among PAG, WAG and polymer flooding. Simulation results show that PAG method would increase oil recovery over 10% compared with other EOR methods and PAG would be economically success based on assumption in this study. This study is the first to apply PAG to enhance oil recovery in heavy oil reservoir with highly heterogeneous. Besides, this paper provides detailed discussions and comparison about PAG with other EOR methods in this heavy oil reservoir.

Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal - Appendix)

Energy Technology Data Exchange (ETDEWEB)

Bou-Mikael, Sami

2002-02-05

The main objective of the Port Neches Project was to determine the feasibility and producibility of CO2 miscible flooding techniques enhanced with horizontal drilling applied to a Fluvial Dominated Deltaic reservoir. The second was to disseminate the knowledge gained through established Technology Transfer mechanisms to support DOE's programmatic objectives of increasing domestic oil production and reducing abandonment of oil fields.

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

DEFF Research Database (Denmark)

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

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

Identification and evaluation of fluvial-dominated deltaic (Class I oil) reservoirs in Oklahoma. Final report, August 1998

Energy Technology Data Exchange (ETDEWEB)

Banken, M.K.

1998-11-01

The Oklahoma Geological Survey (OGS), the Geo Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma have engaged in a five-year program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program included a systematic and comprehensive collection and evaluation of information on all FDD oil reservoirs in Oklahoma and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. The execution of this project was approached in phases. The first phase began in January, 1993 and consisted of planning, play identification and analysis, data acquisition, database development, and computer systems design. By the middle of 1994, many of these tasks were completed or nearly finished including the identification of all FDD reservoirs in Oklahoma, data collection, and defining play boundaries. By early 1995, a preliminary workshop schedule had been developed for project implementation and technology transfer activities. Later in 1995, the play workshop and publication series was initiated with the Morrow and the Booch plays. Concurrent with the initiation of the workshop series was the opening of a computer user lab that was developed for use by the petroleum industry. Industry response to the facility initially was slow, but after the first year lab usage began to increase and is sustaining. The remaining six play workshops were completed through 1996 and 1997, with the project ending on December 31, 1997.

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

Energy Technology Data Exchange (ETDEWEB)

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

1999-02-24

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

Microbial enhanced oil recovery and compositions therefor

Science.gov (United States)

Bryant, Rebecca S.

1990-01-01

A method is provided for microbial enhanced oil recovery, wherein a combination of microorganisms is empirically formulated based on survivability under reservoir conditions and oil recovery efficiency, such that injection of the microbial combination may be made, in the presence of essentially only nutrient solution, directly into an injection well of an oil bearing reservoir having oil present at waterflood residual oil saturation concentration. The microbial combination is capable of displacing residual oil from reservoir rock, which oil may be recovered by waterflooding without causing plugging of the reservoir rock. Further, the microorganisms are capable of being transported through the pores of the reservoir rock between said injection well and associated production wells, during waterflooding, which results in a larger area of the reservoir being covered by the oil-mobilizing microorganisms.

Strength and Biot's coefficient for high-porosity oil- or water-saturated chalk

DEFF Research Database (Denmark)

Andreassen, Katrine Alling

. The Biot coefficient states the degree of cementation or how the pore pressure contributes to the strain resulting from an external load for a porous material. It is here calculated from dynamic measurements and correlated with the strength of outcrop chalk characterized by the onset of pore collapse...... during hydrostatic loading. The hypothesis is that the Biot coefficient and the theory of poroelasticity may cover the fluid effect by including the increased fluid bulk modulus from oil to water. A high number of test results for both oil- and water-saturated high-porosity outcrop chalk show correlation......In the petroleum industry it is relevant to know the Biot coefficient for establishing the effective stresses present in both the overburden and for the reservoir interval. When depleting a reservoir it is important to estimate the settlement through the strain imposed by the effective stress. Also...

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

DEFF Research Database (Denmark)

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

2015-01-01

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

Smart waterflooding in carbonate reservoirs

Energy Technology Data Exchange (ETDEWEB)

Zahid, A.

2012-02-15

During the last decade, smart waterflooding has been developed into an emerging EOR technology both for carbonate and sandstone reservoirs that does not require toxic or expensive chemicals. Although it is widely accepted that different salinity brines may increase the oil recovery for carbonate reservoirs, understanding of the mechanism of this increase is still developing. To understand this smart waterflooding process, an extensive research has been carried out covering a broad range of disciplines within surface chemistry, thermodynamics of crude oil and brine, as well as their behavior in porous media. The main conclusion of most previous studies was that it is the rock wettability alteration towards more water wetting condition that helps improving the oil recovery. In the first step of this project, we focused on verifying this conclusion. Coreflooding experiments were carried out using Stevens Klint outcrop chalk core plugs with brines without sulfate, as well as brines containing sulfate in different concentrations. The effects of temperature, injection rate, crude oil composition and different sulfate concentrations on the total oil recovery and the recovery rate were investigated. Experimental results clearly indicate improvement of the oil recovery without wettability alteration. At the second step of this project, we studied crude oil/brine interactions under different temperatures, pressures and salinity conditions in order to understand mechanisms behind the high salinity waterflooding. Our results show, in particular that sulfate ions may help decreasing the crude oil viscosity or formation of, seemingly, an emulsion phase between sulfate-enriched brine and oil at high temperature and pressure. Experimental results indicate that crude oils interact differently with the same brine solutions regarding phase behavior and viscosity measurements. This difference is attributed to the difference in composition of the different crude oils. More experiments

A Time Domain Update Method for Reservoir History Matching of Electromagnetic Data

KAUST Repository

Katterbauer, Klemens; Hoteit, Ibrahim; Sun, Shuyu

2014-01-01

production forecasts and optimizing reservoir exploitation. Reservoir history matching has played here a key role incorporating production, seismic, electromagnetic and logging data for forecasting the development of reservoirs and its depletion

Microbial ecology of methanogenic crude oil biodegradation; from microbial consortia to heavy oil

Energy Technology Data Exchange (ETDEWEB)

Head, Ian M.; Maguire, Michael J.; Sherry, Angela; Grant, Russell; Gray, Neil D.; Aitken, Carolyn M.; Martin Jones, D.; Oldenburg, Thomas B.P.; Larter, Stephen R. [Petroleum Research Group, Geosciences, University of Calgary (Canada)

2011-07-01

This paper presents the microbial ecology of methanogenic crude oil biodegradation. Biodegraded petroleum reservoirs are one of the most dramatic indications of the deep biosphere. It is estimated that heavy oil and oil sands will account for a considerable amount of energy production in the future. Carbon, a major resource for deep subsurface microorganisms, and energy are contained in large quantities in petroleum reservoirs. The aerobic to anaerobic paradigm shift is explained. A key process for in-situ oil biodegradation in petroleum reservoirs is methanogenesis. New paradigms for in-reservoir crude oil biodegradation are discussed. Variations in anaerobic degradation of crude oil hydrocarbons are also discussed. A graph shows the different patterns of crude oil biodegradation under sulfate-reducing and methanogenic conditions. Alternative anaerobic alkane activation mechanisms are also shown. From the study, it can be concluded that methanogenic crude oil degradation is of global importance and led to the establishment of the world's enormous heavy oil deposits.

Genome-Resolved Metagenomic Analysis Reveals Roles for Candidate Phyla and Other Microbial Community Members in Biogeochemical Transformations in Oil Reservoirs

Directory of Open Access Journals (Sweden)

Ping Hu

2016-01-01

Full Text Available Oil reservoirs are major sites of methane production and carbon turnover, processes with significant impacts on energy resources and global biogeochemical cycles. We applied a cultivation-independent genomic approach to define microbial community membership and predict roles for specific organisms in biogeochemical transformations in Alaska North Slope oil fields. Produced water samples were collected from six locations between 1,128 m (24 to 27°C and 2,743 m (80 to 83°C below the surface. Microbial community complexity decreased with increasing temperature, and the potential to degrade hydrocarbon compounds was most prevalent in the lower-temperature reservoirs. Sulfate availability, rather than sulfate reduction potential, seems to be the limiting factor for sulfide production in some of the reservoirs under investigation. Most microorganisms in the intermediate- and higher-temperature samples were related to previously studied methanogenic and nonmethanogenic archaea and thermophilic bacteria, but one candidate phylum bacterium, a member of the Acetothermia (OP1, was present in Kuparuk sample K3. The greatest numbers of candidate phyla were recovered from the mesothermic reservoir samples SB1 and SB2. We reconstructed a nearly complete genome for an organism from the candidate phylum Parcubacteria (OD1 that was abundant in sample SB1. Consistent with prior findings for members of this lineage, the OD1 genome is small, and metabolic predictions support an obligately anaerobic, fermentation-based lifestyle. At moderate abundance in samples SB1 and SB2 were members of bacteria from other candidate phyla, including Microgenomates (OP11, Atribacteria (OP9, candidate phyla TA06 and WS6, and Marinimicrobia (SAR406. The results presented here elucidate potential roles of organisms in oil reservoir biological processes.

Analysis of Microbial Communities in the Oil Reservoir Subjected to CO2-Flooding by Using Functional Genes as Molecular Biomarkers for Microbial CO2 Sequestration

Directory of Open Access Journals (Sweden)

Jin-Feng eLiu

2015-03-01

Full Text Available Sequestration of CO2 in oil reservoirs is considered to be one of the feasible options for mitigating atmospheric CO2 building up and also for the in situ potential bioconversion of stored CO2 to methane. However, the information on these functional microbial communities and the impact of CO2 storage on them is hardly available. In this paper a comprehensive molecular survey was performed on microbial communities in production water samples from oil reservoirs experienced CO2-flooding by analysis of functional genes involved in the process, including cbbM, cbbL, fthfs, [FeFe]-hydrogenase and mcrA. As a comparison, these functional genes in the production water samples from oil reservoir only experienced water-flooding in areas of the same oil bearing bed were also analyzed. It showed that these functional genes were all of rich diversity in these samples, and the functional microbial communities and their diversity were strongly affected by a long-term exposure to injected CO2. More interestingly, microorganisms affiliated with members of the genera Methanothemobacter, Acetobacterium and Halothiobacillus as well as hydrogen producers in CO2 injected area either increased or remained unchanged in relative abundance compared to that in water-flooded area, which implied that these microorganisms could adapt to CO2 injection and, if so, demonstrated the potential for microbial fixation and conversion of CO2 into methane in subsurface oil reservoirs.

Evaluation of sediment management strategies on reservoir storage depletion rate: a case study

NARCIS (Netherlands)

Ali, M.; Sterk, G.

2010-01-01

Sedimentation aspects have a major role during the design of new reservoir projects because life of the reservoir mainly depends upon sediment handling during reservoir operation. Therefore, proper sediment management strategies should be adopted to enhance the life span of reservoirs. Basha

Geochemical controls of the oils acidity in petroleum reservoirs; Controles geochimiques de l'acidite des huiles dans les reservoirs petroliers

Energy Technology Data Exchange (ETDEWEB)

Rouquette, N.

2004-12-01

Within the framework of this thesis, we were interested in the study of acid oils. Thus, after having developed an analytical method to separate acids from crude oils, this one was applied to the analysis of several series of acid oils presenting various degrees of biodegradation. In the first chapter devoted to their molecular study, it was shown that the alteration of the organic matter proceeds according to a quasi-stepwise order and that the major part of the carboxylic acids appeared as an Unresolved Complex Mixture. The only identified resolved compounds were apparently not formed by biodegradation of the oil in place but rather seem either to have been incorporated during oil migration, or to correspond to compounds initially present in the reservoir rock. Among those, we isolated and identified by NMR a new higher plant tri-terpenic derivative, the 24-nor,28-lupanoic acid. In the second chapter, a new method to evaluate acidity, applicable to small quantities of oil, was developed. This one is based on the methylation of the acid species by iodo-methane marked with carbon 13. In the case of a series from the Gulf of Guinea tested initially, the enrichment after labelling presents a perfect correlation with the values of acidity measured by the TAN method (for 'Total Acid Number'). The isotopic labelling method was applied later to a broader range of oil samples. As a whole, a linear correlation seems to exist between {sup 13}C labelling and TAN index, which lets consider that this method could represent an interesting alternative to the measurement of the TAN index in oil exploration. (author)

Application of Reservoir Characterization and Advanced Technology to Improve Recovery and Economics in a Lower Quality Shallow Shelf Carbonate Reservoir

International Nuclear Information System (INIS)

Taylor, Archie R.

1996-01-01

The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three dimensional (3-D) seismic; (3) Cross-well bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO 2 ) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents

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

Energy Technology Data Exchange (ETDEWEB)

Marsters, S.

2003-06-01

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

Enabling technology: an overview of offshore innovations in the oil industry

Energy Technology Data Exchange (ETDEWEB)

Amado, Luiz C.N. [Shell International Exploration and Production (E and P) Inc., Houston, TX (Brazil)

2008-07-01

Big accumulations found in the past are not likely to occur again. On the contrary several small size accumulations may still be there unless a new play be discovered such as the sub salt. With global demand for oil rapidly increasing and easy oil becoming scarcer, we need to start looking at more difficult reservoirs from which to produce hydrocarbons. To boost daily global oil supplies to 100 million barrels, against current levels of some 85 million barrels, will be 'extremely difficult to reach' as we have heard in the news. It is not a question of available oil reserves, but a combination of technology, geopolitics and actual production decline in existing fields. Geopolitics and depletion rates are highly complex variables upon which we do not have full control. However Technology can still be designed fit for purposes. (author)

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

International Nuclear Information System (INIS)

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

1979-01-01

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

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

DEFF Research Database (Denmark)

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

2015-01-01

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

Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal - Appendix); FINAL

International Nuclear Information System (INIS)

Bou-Mikael, Sami

2002-01-01

The main objective of the Port Neches Project was to determine the feasibility and producibility of CO2 miscible flooding techniques enhanced with horizontal drilling applied to a Fluvial Dominated Deltaic reservoir. The second was to disseminate the knowledge gained through established Technology Transfer mechanisms to support DOE's programmatic objectives of increasing domestic oil production and reducing abandonment of oil fields

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.

APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

International Nuclear Information System (INIS)

Hickman, T. Scott

2003-01-01

The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three-dimensional (3-D) seismic; (3) Crosswell bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO 2 ) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents

APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

International Nuclear Information System (INIS)

Raj Kumar; Keith Brown; Hickman, T. Scott; Justice, James J.

2000-01-01

The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three-dimensional (3-D) seismic; (3) Crosswell bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO 2 ) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents

APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

International Nuclear Information System (INIS)

Hickman, T. Scott; Justice, James J.

2001-01-01

The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three-dimensional (3-D) seismic; (3) Crosswell bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO 2 ) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents

APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

Energy Technology Data Exchange (ETDEWEB)

T. Scott Hickman; James J. Justice

2001-06-16

The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three-dimensional (3-D) seismic; (3) Crosswell bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO{sub 2}) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents.

Vapor pressure lowering effects due to salinity and suction pressure in the depletion of vapor-dominated geothermal reservoirs

Energy Technology Data Exchange (ETDEWEB)

Battistelli, A. [Aquater S.p.A., Pisa (Italy); Calore, C. [Istituto Internazionale per le Ricerche Geotermiche-CNR, Pisa (Italy); Pruess, K. [Lawrence Berkeley Lab., Berkeley, CA (United States)

1995-03-01

The equation-of-state module able to handle saline brines with non-condensible gas, developed for the TOUGH2 simulator, has been improved to include vapor pressure lowering (VPL) due to suction pressure as represented by Kelvin`s equation. In this equation the effects of salt are considered whereas those of non-condensible gas have currently been neglected. Numerical simulations of fluid production from tight matrix blocks have been performed to evaluate the impact of VPL effects due to salinity and suction pressure on the depletion behaviour of vapor-dominated geothermal reservoirs. Previous studies performed neglected VPL due to suction pressure showed that for initial NaCl mass fractions above threshold values, {open_quotes}sealing{close_quotes} of the block occurs and large amounts of liquid fluid may not be recovered. On the other hand, below the threshold value the matrix block dries out due to fluid production. The inclusion of VPL due to suction pressure does not allow complete vaporization of the liquid phase. As a result, the threshold NaCl concentration above which sealing of the matrix block occurs is increased. Above the {open_quotes}critical{close_quotes} NaCl concentration, block depletion behaviour with and without the VPL due to suction pressure is almost identical, as liquid phase saturation remains high even after long production times. As the VPL due to suction pressure depends mainly on capillary pressure, the shape of capillary pressure functions used in numerical simulations is important in determining VPL effects on block depletion.

Oil geochemistry of the Putumayo basin

International Nuclear Information System (INIS)

Ramon, J.C

1996-01-01

Bio marker fingerprinting of 2O crude oils from Putumayo Basin, Colombia, shows a vertical segregation of oil families. The Lower Cretaceous reservoirs (Caballos and 'U' Villeta sands) contain oils that come from a mixture of marine and terrestrial organic matter, deposited in a marginal, 'oxic' marine setting. The Upper Cretaceous ('T' and N ' sands) and Tertiary reservoirs contain oils with marine algal input deposited in a reducing, carbonate-rich environment. Lithology, environmental conditions and organic matter type of source rocks as predicted from oil bio marker differences correspond to organic composition of two Cretaceous source rocks. Vertical heterogeneity in the oils, even those from single wells, suggests the presence of two isolated petroleum systems. Hydrocarbons from Lower Cretaceous source rocks charged Lower Cretaceous reservoirs whereas oils from Upper Cretaceous source rocks charged Upper Cretaceous and Tertiary reservoirs. Oil migration from mature source rocks into multiple reservoirs has been stratigraphically up dip along the regional sandstone units and vertical migration through faults has been limited. Bio marker maturity parameters indicate that all oils were generated from early thermal maturity oil window

Principles of heavy oil recovery

Energy Technology Data Exchange (ETDEWEB)

Szasz, S.E.; Thomas, G.W.

1965-10-01

Rising exploration costs have prompted greater interest in the large known deposits of heavy oil in North America. Because of high oil viscosities in such reservoirs, recoveries are poor, fluid drives are inefficient and production rates are uneconomical. Viscosity reduction can best be accomplished by heating the reservoir. The basic aspects of reservoir heating are reviewed and those processes which are of practical importance in heavy oil reservoirs are discussed. Wellbore heating frequently can be applied to heavy oil reservoirs to increase production rates. In hot waterflooding, the water requirements are much higher than an ordinary waterflood. Steam floods are more attractive, but operating costs are generally high. Conduction heating processes appear most promising. Among these is included the cyclic steam-soak process. A simple method is presented for estimating the performance from the first cycle of steam injection into the formation, assuming gravity as the only driving energy. An example calculation for a typical heavy oil reservoir is given. (26 refs.)

Multigrid Methods for Fully Implicit Oil Reservoir Simulation

Science.gov (United States)

Molenaar, J.

1996-01-01

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

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

DEFF Research Database (Denmark)

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

2012-01-01

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

Feasibility of using electrical downhole heaters in Faja heavy oil reservoirs

Energy Technology Data Exchange (ETDEWEB)

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

2008-10-15

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

Innovative MIOR Process Utilizing Indigenous Reservoir Constituents

Energy Technology Data Exchange (ETDEWEB)

D. O. Hitzman; A. K. Stepp; D. M. Dennis; L. R. Graumann

2003-03-31

This research program is directed at improving the knowledge of reservoir ecology and developing practical microbial solutions for improving oil production. The goal is to identify indigenous microbial populations which can produce beneficial metabolic products and develop a methodology to stimulate those select microbes with nutrient amendments to increase oil recovery. This microbial technology has the capability of producing multiple oil-releasing agents. Experimental laboratory work is underway. Microbial cultures have been isolated from produced water samples. Comparative laboratory studies demonstrating in situ production of microbial products as oil recovery agents were conducted in sand packs with natural field waters with cultures and conditions representative of oil reservoirs. Field pilot studies are underway.

The role of nitrogen and sulphur bearing compounds in the wettability of oil reservoir rocks: an approach with nuclear microanalysis and other related surface techniques

International Nuclear Information System (INIS)

Mercier, F.; Toulhoat, N.; Potocek, V.; Trocellier, P.

1999-01-01

Oil recovery is strongly influenced by the wettability of the reservoir rock. Some constituents of the crude oil (polar compounds and heavy fractions such as asphaltenes with heteroatoms) are believed to react with the reservoir rock and to condition the local wettability. Therefore, it is important to obtain as much knowledge as possible about the characteristics of the organic matter/mineral interactions. This study is devoted to the description at the microscopic scale of the distribution of some heavy fractions of crude oil (asphaltenes) and nitrogen molecules (pyridine and pyrrole) on model minerals of sandstone reservoir rocks such as silica and clays. Nuclear microanalysis, X-Ray Photoelectron Spectroscopy and other related microscopic imaging techniques allow to study the distribution and thickness of the organic films. The respective influences of the nature of the mineral substrate and the organic matter are studied. The important role played by the nitrogen compounds in the adsorption of organic matter is emphasized

Data Compression of Hydrocarbon Reservoir Simulation Grids

KAUST Repository

Chavez, Gustavo Ivan

2015-05-28

A dense volumetric grid coming from an oil/gas reservoir simulation output is translated into a compact representation that supports desired features such as interactive visualization, geometric continuity, color mapping and quad representation. A set of four control curves per layer results from processing the grid data, and a complete set of these 3-dimensional surfaces represents the complete volume data and can map reservoir properties of interest to analysts. The processing results yield a representation of reservoir simulation results which has reduced data storage requirements and permits quick performance interaction between reservoir analysts and the simulation data. The degree of reservoir grid compression can be selected according to the quality required, by adjusting for different thresholds, such as approximation error and level of detail. The processions results are of potential benefit in applications such as interactive rendering, data compression, and in-situ visualization of large-scale oil/gas reservoir simulations.

Method for enhanced oil recovery

Science.gov (United States)

Comberiati, Joseph R.; Locke, Charles D.; Kamath, Krishna I.

1980-01-01

The present invention is directed to an improved method for enhanced recovery of oil from relatively "cold" reservoirs by carbon dioxide flooding. In oil reservoirs at a temperature less than the critical temperature of 87.7.degree. F. and at a pore pressure greater than the saturation pressure of carbon dioxide at the temperature of the reservoir, the carbon dioxide remains in the liquid state which does not satisfactorily mix with the oil. However, applicants have found that carbon dioxide can be vaporized in situ in the reservoir by selectively reducing the pore pressure in the reservoir to a value less than the particular saturated vapor pressure so as to greatly enhance the mixing of the carbon dioxide with the oil.

Aging Reservoirs in a Changing Climate: Examining Storage Loss of Large Reservoirs and Variability of Sedimentation Rate in a Dominant Cropland Region

Science.gov (United States)

Rahmani, V.; Kastens, J.; deNoyelles, F.; Huggins, D.; Martinko, E.

2015-12-01

Dam construction has multiple environmental and hydrological consequences including impacts on upstream and downstream ecosystems, water chemistry, and streamflow. Behind the dam the reservoir can trap sediment from the stream and fill over time. With increasing population and drinking and irrigation water demands, particularly in the areas that have highly variable weather and extended drought periods such as the United States Great Plains, reservoir sedimentation escalates water management concerns. Under nearly all projected climate change scenarios we expect that reservoir water storage and management will come under intense scrutiny because of the extensive use of interstate river compacts in the Great Plains. In the state of Kansas, located in the Great Plains, bathymetric surveys have been completed during the last decade for many major lakes by the Kansas Biological Survey, Kansas Water Office, and the U.S. Army Corps of Engineers. In this paper, we studied the spatial and temporal changes of reservoir characteristics including sedimentation yield, depletion rate, and storage capacity loss for 24 federally-operated reservoirs in Kansas. These reservoirs have an average age of about 50 years and collectively have lost approximately 15% of their original capacity, with the highest annual observed single-reservoir depletion rate of 0.84% and sedimentation yield of 1,685 m3 km-2 yr-1.

PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

Energy Technology Data Exchange (ETDEWEB)

Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

2004-05-01

The Permian Basin of west Texas and southeast New Mexico has produced >30 Bbbl (4.77 x 10{sup 9} m{sup 3}) of oil through 2000, most of it from 1,339 reservoirs having individual cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}). These significant-sized reservoirs are the focus of this report. Thirty-two Permian Basin oil plays were defined, and each of the 1,339 significant-sized reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. Associated reservoir information within linked data tables includes Railroad Commission of Texas reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are <1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. This report contains a summary description of each play, including key reservoir characteristics and successful reservoir-management practices that have been used in the play. The CD accompanying the report contains a pdf version of the report, the GIS project, pdf maps of all plays, and digital data files. Oil production from the reservoirs in the Permian Basin having cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 from these significant-sized reservoirs was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl 5.25 x 10{sup 8} m{sup 3}), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres

The Potential of a Surfactant/Polymer Flood in a Middle Eastern Reservoir

Directory of Open Access Journals (Sweden)

Meshal Algharaib

2012-01-01

Full Text Available An integrated full-field reservoir simulation study has been performed to determine the reservoir management and production strategies in a mature sandstone reservoir. The reservoir is a candidate for an enhanced oil recovery process or otherwise subject to abandonment. Based on its charateristics, the reservoir was found to be most suited for a surfactant/polymer (SP flood. The study started with a large data gathering and the building of a full-field three-dimensional geological model. Subsequently, a full field simulation model was built and used to history match the water flood. The history match of the water flood emphasizes the areas with remaining high oil saturations, establishes the initial condition of the reservoir for an SP flood, and generates a forecast of reserves for continued water flood operations. A sector model was constructed from the full field model and then used to study different design parameters to maximize the project profitability from the SP flood. An economic model, based on the estimated recovery, residual oil in-place, oil price, and operating costs, has been implemented in order to optimize the project profitability. The study resulted in the selection of surfactant and polymer concentrations and slug size that yielded the best economic returns when applied in this reservoir. The study shows that, in today’s oil prices, surfactant/polymer flood when applied in this reservoir has increased the ultimate oil recovery and provide a significant financial returns.

The egg model - a geological ensemble for reservoir simulation

NARCIS (Netherlands)

Jansen, J.D.; Fonseca, R.M.; Kahrobaei, S.; Siraj, M.M.; Essen, van G.M.; Hof, Van den P.M.J.

2014-01-01

The ‘Egg Model’ is a synthetic reservoir model consisting of an ensemble of 101 relatively small three-dimensional realizations of a channelized oil reservoir produced under water flooding conditions with eight water injectors and four oil producers. It has been used in numerous publications to

Hydrodynamic modeling of petroleum reservoirs using simulator MUFITS

Science.gov (United States)

Afanasyev, Andrey

2015-04-01

MUFITS is new noncommercial software for numerical modeling of subsurface processes in various applications (www.mufits.imec.msu.ru). To this point, the simulator was used for modeling nonisothermal flows in geothermal reservoirs and for modeling underground carbon dioxide storage. In this work, we present recent extension of the code to petroleum reservoirs. The simulator can be applied in conventional black oil modeling, but it also utilizes a more complicated models for volatile oil and gas condensate reservoirs as well as for oil rim fields. We give a brief overview of the code by providing the description of internal representation of reservoir models, which are constructed of grid blocks, interfaces, stock tanks as well as of pipe segments and pipe junctions for modeling wells and surface networks. For conventional black oil approach, we present the simulation results for SPE comparative tests. We propose an accelerated compositional modeling method for sub- and supercritical flows subjected to various phase equilibria, particularly to three-phase equilibria of vapour-liquid-liquid type. The method is based on the calculation of the thermodynamic potential of reservoir fluid as a function of pressure, total enthalpy and total composition and storing its values as a spline table, which is used in hydrodynamic simulation for accelerated PVT properties prediction. We provide the description of both the spline calculation procedure and the flashing algorithm. We evaluate the thermodynamic potential for a mixture of two pseudo-components modeling the heavy and light hydrocarbon fractions. We develop a technique for converting black oil PVT tables to the potential, which can be used for in-situ hydrocarbons multiphase equilibria prediction under sub- and supercritical conditions, particularly, in gas condensate and volatile oil reservoirs. We simulate recovery from a reservoir subject to near-critical initial conditions for hydrocarbon mixture. We acknowledge

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

Technological change, depletion and environmental policy in the offshore oil and gas industry

Science.gov (United States)

Managi, Shunsuke

Technological change is central to maintaining standards of living in modern economies with finite resources and increasingly stringent environmental goals. Successful environmental policies can contribute to efficiency by encouraging, rather than inhibiting, technological innovation. However, little research to date has focused on the design and implementation of environmental regulations that encourage technological progress, or in insuring productivity improvements in the face of depletion of natural resources and increasing stringency of environmental regulations. This study models and measures productivity change, with an application to offshore oil and gas production in the Gulf of Mexico using Data Envelopment Analysis. This is an important application because energy resources are central to sustaining our economy. The net effects of technological progress and depletion on productivity of offshore oil and gas production are measured using a unique field-level set of data of production from all wells in the Gulf of Mexico over the time period from 1946--1998. Results are consistent with the hypothesis that technological progress has mitigated depletion effects over the study period, but the pattern differs from the conventional wisdom for nonrenewable resource industries. The Porter Hypothesis was recast, and revised version was tested. The Porter Hypothesis states that well designed environmental regulations can potentially contribute to productive efficiency in the long run by encouraging innovation. The Porter Hypothesis was recast to include market and nonmarket outputs. Our results support the recast version of Porter hypothesis, which examine productivity of joint production of market and environmental outputs. But we find no evidence for the standard formulation of the Porter hypothesis, that increased stringency of environmental regulation lead to increased productivity of market outputs and therefore increased industry profits. The model is used to

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

Energy Technology Data Exchange (ETDEWEB)

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

2010-07-01

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

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.

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

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)

Determination of the vertical distribution and areal of the composition in volatile oil and/or gas condensate reservoirs

International Nuclear Information System (INIS)

Santos Santos, Nicolas; Ortiz Cancino, Olga Patricia; Barrios Ortiz, Wilson

2005-01-01

The compositional variation in vertical and areal direction due to gravitational and thermal effects plays an important role in the determination of the original reserves in-situ and in the selection of the operation scheme for volatile oil and/or gas condensate reservoirs. In this work we presented the mathematical formulation of the thermodynamic behavior experienced by compositional fluids, such as volatile oil and/or gas condensate, under the influence of the mentioned effects (gravitational and thermal), which was implemented in a software tool, this tool determine the compositional variation in vertical direction and, in addition, it allows to know the saturation pressure variation in the hydrocarbon column and the location of the gas-oil contact. With the obtained results, product of the use of this tool, was developed a methodology to obtain one first approach of the compositional variation in areal direction to obtain compositional spatial distribution (iso composition maps) in the reservoir, for components like the methane, which experiences the greater variations. These iso composition maps allow to determine the location of the hydrocarbon deposits, in such a way that the production strategies can be selected and be applied to maximize the recovery, such as in fill wells, perforation of new zones, EOR processes, etc

Advanced waterflooding in chalk reservoirs: Understanding of underlying mechanisms

DEFF Research Database (Denmark)

Zahid, Adeel; Sandersen, Sara Bülow; Stenby, Erling Halfdan

2011-01-01

Over the last decade, a number of studies have shown SO42−, Ca2+ and Mg2+ to be potential determining ions, which may be added to the injected brine for improving oil recovery during waterflooding in chalk reservoirs. However the understanding of the mechanism leading to an increase in oil recove...... of a microemulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs besides the mechanism of the rock wettability alteration, which has been reported in most previous studies.......Over the last decade, a number of studies have shown SO42−, Ca2+ and Mg2+ to be potential determining ions, which may be added to the injected brine for improving oil recovery during waterflooding in chalk reservoirs. However the understanding of the mechanism leading to an increase in oil recovery...

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

Directory of Open Access Journals (Sweden)

Soheil Bahrekazemi

2017-09-01

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

Geological and production characteristics of strandplain/barrier island reservoirs in the United States

Energy Technology Data Exchange (ETDEWEB)

Cole, E.L.; Fowler, M.; Jackson, S.; Madden, M.P.; Reeves, T.K.; Salamy, S.P.; Young, M.A.

1994-12-01

The Department of Energy`s (DOE`s) primary mission in the oil research program is to maximize the economically and environmentally sound recovery of oil from domestic reservoirs and to preserve access to this resource. The Oil Recovery Field Demonstration Program supports DOE`s mission through cost-shared demonstrations of improved Oil Recovery (IOR) processes and reservoir characterization methods. In the past 3 years, the DOE has issued Program Opportunity Notices (PONs) seeking cost-shared proposals for the three highest priority, geologically defined reservoir classes. The classes have been prioritized based on resource size and risk of abandonment. This document defines the geologic, reservoir, and production characteristics of the fourth reservoir class, strandplain/barrier islands. Knowledge of the geological factors and processes that control formation and preservation of reservoir deposits, external and internal reservoir heterogeneities, reservoir characterization methodology, and IOR process application can be used to increase production of the remaining oil-in-place (IOR) in Class 4 reservoirs. Knowledge of heterogeneities that inhibit or block fluid flow is particularly critical. Using the TORIS database of 330 of the largest strandplain/barrier island reservoirs and its predictive and economic models, the recovery potential which could result from future application of IOR technologies to Class 4 reservoirs was estimated to be between 1.0 and 4.3 billion barrels, depending on oil price and the level of technology advancement. The analysis indicated that this potential could be realized through (1) infill drilling alone and in combination with polymer flooding and profile modification, (2) chemical flooding (sufactant), and (3) thermal processes. Most of this future potential is in Texas, Oklahoma, and the Rocky Mountain region. Approximately two-thirds of the potentially recoverable resource is at risk of abandonment by the year 2000.

Rock Physics of Reservoir Rocks with Varying Pore Water Saturation and Pore Water Salinity

DEFF Research Database (Denmark)

Katika, Konstantina

experiments, the rock is subjected to high external stresses that resemble the reservoir stresses; 2) the fluid distribution within the pore space changes during the flow through experiments and wettability alterations may occur; 3) different ions, present in the salt water injected in the core, interact......Advanced waterflooding (injection of water with selective ions in reservoirs) is a method of enhanced oil recovery (EOR) that has attracted the interest of oil and gas companies that exploit the Danish oil and gas reservoirs. This method has been applied successfully in oil reservoirs...... and in the Smart Water project performed in a laboratory scale in order to evaluate the EOR processes in selected core plugs. A major step towards this evaluation is to identify the composition of the injected water that leads to increased oil recovery in reservoirs and to define changes in the petrophysical...

Prokaryotic community structure and activity of sulfate reducers in production water from high-temperature oil reservoirs with and without nitrate treatment

DEFF Research Database (Denmark)

Gittel, Antje; Sørensen, Ketil; Skovhus, Torben L.

2009-01-01

Sulfate-reducing prokaryotes (SRP) cause severe problems like microbial corrosion and reservoir souring in seawater-injected oil production systems. One strategy to control SRP activity is the addition of nitrate to the injection water. Production waters from two adjacent, hot (80°C) oil reservoirs......, one with and one without nitrate treatment, were compared for prokaryotic community structure and activity of SRP. Bacterial and archaeal 16S rRNA gene analyses revealed higher prokaryotic abundance but lower diversity for the nitrate-treated field. The 16S rRNA gene clone libraries from both fields...... were dominated by sequences affiliated with Firmicutes (Bacteria) and Thermococcales (Archaea). Potential heterotrophic nitrate reducers (Deferribacterales) were exclusively found at the nitrate-treated field, possibly stimulated by nitrate addition. Quantitative PCR of dsrAB genes revealed...

Development of gas and gas condensate reservoirs

Energy Technology Data Exchange (ETDEWEB)

NONE

1995-12-01

In the study of gas reservoir development, the first year topics are restricted on reservoir characterization. There are two types of reservoir characterization. One is the reservoir formation characterization and the other is the reservoir fluid characterization. For the reservoir formation characterization, calculation of conditional simulation was compared with that of unconditional simulation. The results of conditional simulation has higher confidence level than the unconditional simulation because conditional simulation considers the sample location as well as distance correlation. In the reservoir fluid characterization, phase behavior calculations revealed that the component grouping is more important than the increase of number of components. From the liquid volume fraction with pressure drop, the phase behavior of reservoir fluid can be estimated. The calculation results of fluid recombination, constant composition expansion, and constant volume depletion are matched very well with the experimental data. In swelling test of the reservoir fluid with lean gas, the accuracy of dew point pressure forecast depends on the component characterization. (author). 28 figs., 10 tabs.

Reservoir heterogeneity in carboniferous sandstone of the Black Warrior basin. Final report

Energy Technology Data Exchange (ETDEWEB)

Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

1994-06-01

Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

Reservoir heterogeneity in Carboniferous sandstone of the Black Warrior basin. Final report

Energy Technology Data Exchange (ETDEWEB)

Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

1994-04-01

Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

Production Optimization for Two-Phase Flow in an Oil Reservoir

DEFF Research Database (Denmark)

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

2012-01-01

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

What about oil reserve depletion and crude oil price evolution?

International Nuclear Information System (INIS)

2007-01-01

The objective of this report is to give a synthesis of different points of view with respect to the 'Peak Oil' perspective and to the crude oil price evolution. In the first part, the authors examine the evolutions and assessments of oil reserves and productions, by discussing the different types of reserve, the optimistic and pessimistic points of views. Then, in the second part, they analyse the long term price formation, the various production technical costs (conventional oils, heavy oils and asphaltic sands, coal- and gas-based synthetic hydrocarbons, bio-fuels), the external costs (notably in relationship with greenhouse emissions), the relationship between geopolitical issues and short and middle term price formation. In the third and last part, they discuss the possible evolutions and scenarios in terms of demand, production, and prices

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

Energy Technology Data Exchange (ETDEWEB)

Murphy, Mark B.

1999-02-24

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

Potential of wheat bran to promote indigenous microbial enhanced oil recovery.

Science.gov (United States)

Zhan, Yali; Wang, Qinghong; Chen, Chunmao; Kim, Jung Bong; Zhang, Hongdan; Yoza, Brandon A; Li, Qing X

2017-06-01

Microbial enhanced oil recovery (MEOR) is an emerging oil extraction technology that utilizes microorganisms to facilitate recovery of crude oil in depleted petroleum reservoirs. In the present study, effects of wheat bran utilization were investigated on stimulation of indigenous MEOR. Biostimulation conditions were optimized with the response surface methodology. The co-application of wheat bran with KNO 3 and NH 4 H 2 PO 4 significantly promoted indigenous MEOR (IMEOR) and exhibited sequential aerobic (O-), facultative (A n -) and anaerobic (A 0 -) metabolic stages. The surface tension of fermented broth decreased by approximately 35%, and the crude oil was highly emulsified. Microbial community structure varied largely among and in different IMEOR metabolic stages. Pseudomonas sp., Citrobacter sp., and uncultured Burkholderia sp. dominated the O-, A n - and early A 0 -stages. Bacillus sp., Achromobacter sp., Rhizobiales sp., Alcaligenes sp. and Clostridium sp. dominated the later A 0 -stage. This study illustrated occurrences of microbial community succession driven by wheat bran stimulation and its industrial potential.

A Novel Method for Performance Analysis of Compartmentalized Reservoirs

Directory of Open Access Journals (Sweden)

Shahamat Mohammad Sadeq

2016-05-01

Full Text Available This paper presents a simple analytical model for performance analysis of compartmentalized reservoirs producing under Constant Terminal Rate (CTR and Constant Terminal Pressure (CTP. The model is based on the well-known material balance and boundary dominated flow equations and is written in terms of capacitance and resistance of a production and a support compartment. These capacitance and resistance terms account for a combination of reservoir parameters which enable the developed model to be used for characterizing such systems. In addition to considering the properties contrast between the two reservoir compartments, the model takes into account existence of transmissibility barriers with the use of resistance terms. The model is used to analyze production performance of unconventional reservoirs, where the multistage fracturing of horizontal wells effectively creates a Stimulated Reservoir Volume (SRV with an enhanced permeability surrounded by a non-stimulated region. It can also be used for analysis of compartmentalized conventional reservoirs. The analytical solutions provide type curves through which the controlling reservoirs parameters of a compartmentalized system can be estimated. The contribution of the supporting compartment is modeled based on a boundary dominated flow assumption. The transient behaviour of the support compartment is captured by application of “distance of investigation” concept. The model shows that depletion of the production and support compartments exhibit two unit slopes on a log-log plot of pressure versus time for CTR. For CTP, however, the depletions display two exponential declines. The depletion signatures are separated by transition periods, which depend on the contribution of the support compartment (i.e. transient or boundary dominated flow. The developed equations can be implemented easily in a spreadsheet application, and are corroborated with the use of a numerical simulation. The study

Play Analysis and Digital Portfolio of Major Oil Reservoirs in the Permian Basin: Application and Transfer of Advanced Geological and Engineering Technologies for Incremental Production Opportunities

Energy Technology Data Exchange (ETDEWEB)

Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

2004-01-13

A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest onshore petroleum-producing basin in the United States. Approximately 1,300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of oil through 2000. Of these significant-sized reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. There are 32 geologic plays that have been defined for Permian Basin oil reservoirs, and each of the 1,300 major reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. The final reservoir shapefile for each play contains the geographic location of each reservoir. Associated reservoir information within the linked data tables includes RRC reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are smaller than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. Oil production from the reservoirs in the Permian Basin having cumulative production of >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl [5.25 x 10{sup 8} m{sup 3}]), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres Platform Carbonate play (2.15 Bbbl [3.42 x 10{sup 8} m{sup 3}]). Detailed studies of three reservoirs

Decision support system for use in smart wells for the development of oil reservoirs; Sistema de apoio a decisao para uso de pocos inteligentes no desenvolvimento de reservatorios de petroleo

Energy Technology Data Exchange (ETDEWEB)

Almeida, Luciana Faletti [Centro Federal de Educacao Tecnologica Celso Suckow da Fonseca (CEFET-RJ), Rio de Janeiro, RJ (Brazil)], e-mail: faletti@ele.puc-rio.br; Pacheco, Marco Aurelio Cavalcanti; Vellasco, Marley Maria Bernardes Rebuzzi; Tupac Valdivia, Yvan Jesus; Lazo, Juan Guillermo [Pontificia Univ. Catolica do Rio de Janeiro (PUC/Rio), RJ (Brazil)], e-mail: marco@ele.puc-rio.br, e-mail: marley@ele.puc-rio.br, e-mail: yvantv@ele.puc-rio.br, e-mail: juan@ele.puc-rio.br

2008-06-15

Reservoir management is an essential task aimed at the challenge of optimizing the exploration of petroliferous reservoirs. In response to such a challenge, the oil and gas industry has been developing new technologies, such as intelligent wells. These wells are intended to reduce the costs of the more commonplace restoring operations by controlling their technology. This work studies the development of intelligent fields and introduces a decision taking support system able to optimize, through evolutionary algorithms, the intelligent well technology control process considering the technical uncertainties: in valves and geological failures. Moreover, the system proposes to support decision taking, to use or not intelligent wells, given a reservoir ready to be explored or to receive expansion investments. The optimization seeks a strategy of pro-active control, in other words, act before the effect, seeking in the initial production times a configuration of valves capable of: delaying the arrival of the water cut of the production wells, accelerate the oil production or to improve the oil recovery. As a result, an operation that maximizes the NPV (Net present value). The model was tested in three reservoirs, the first being a synthetic reservoir, and the others with more realistic characteristics. (author)

Calcium-Mediated Adhesion of Nanomaterials in Reservoir Fluids.

Science.gov (United States)

Eichmann, Shannon L; Burnham, Nancy A

2017-09-14

Globally, a small percentage of oil is recovered from reservoirs using primary and secondary recovery mechanisms, and thus a major focus of the oil industry is toward developing new technologies to increase recovery. Many new technologies utilize surfactants, macromolecules, and even nanoparticles, which are difficult to deploy in harsh reservoir conditions and where failures cause material aggregation and sticking to rock surfaces. To combat these issues, typically material properties are adjusted, but recent studies show that adjusting the dispersing fluid chemistry could have significant impact on material survivability. Herein, the effect of injection fluid salinity and composition on nanomaterial fate is explored using atomic force microscopy (AFM). The results show that the calcium content in reservoir fluids affects the interactions of an AFM tip with a calcite surface, as surrogates for nanomaterials interacting with carbonate reservoir rock. The extreme force sensitivity of AFM provides the ability to elucidate small differences in adhesion at the pico-Newton (pN) level and provides direct information about material survivability. Increasing the calcium content mitigates adhesion at the pN-scale, a possible means to increase nanomaterial survivability in oil reservoirs or to control nanomaterial fate in other aqueous environments.

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

Post waterflood CO{sub 2} miscible flood in light oil, fluvial-dominated deltaic reservoir. Annual report, October 1, 1993--September 30, 1994

Energy Technology Data Exchange (ETDEWEB)

Bou-Mikael, S.

1995-07-01

Texaco Exploration and Production Inc. (TEPI) and the U.S. Department of Energy (DOE) entered into a cost sharing cooperative agreement to conduct an Enhanced Oil Recovery demonstration project at Port Neches. The field is located in Orange County near Beaumont, Texas. The project will demonstrate the effectiveness of the CO{sub 2}, miscible process in Fluvial Dominated Deltaic reservoirs. It will also evaluate the use of horizontal CO{sub 2} injection wells to improve the overall sweep efficiency. A data base of FDD reservoirs for the gulf coast region will be developed by LSU, using a screening model developed by Texaco Research Center in Houston. Finally, the results and the information gained from this project will be disseminated throughout the oil industry via a series of SPE papers and industry open forums. Reservoir characterization efforts for the Marginulina sand, are in progress utilizing conventional and advanced technologies including 3-D seismic. Sidewall and conventional. cores were cut and analyzed, lab tests were conducted on reservoir fluids, reservoir BHP pressure and reservoir voidage were monitored as shown. Texaco is utilizing the above data to develop a Stratamodel to best describe and characterize the reservoir and to use it as an input for the compositional simulator. The current compositional model is being revised to integrate the new data from the 3-D seismic and field performance under CO{sub 2} injection, to ultimately develop an accurate economic model. All facilities work has been completed and placed in service including the CO{sub 2} pipeline and metering equipment, CO{sub 2} injection and production equipment, water injection equipment, well work and injection/production lines. The horizontal injection well was drilled and completed on January 15, 1994. CO{sub 2} purchases from Cardox continue at an average rate of 3600 MCFD. The CO{sub 2} is being injected at line pressure of 1350 psi.

Successful water management for the oil sands industry

International Nuclear Information System (INIS)

Braun, B.

2003-01-01

Water is a key requirement to produce oil from thermal oil sands projects. Historically, water was considered as a renewable resource that could be used when necessary. Water use is currently examined in a wider context. Canadian Natural Resources Limited has used fresh water for thermal projects in the past, including its thermal operations at Primrose and Wolf Lake. However, technical advancements have made it possible to use recycled water. This allows companies to survive within their licenses while increasing production. Other advances include the use of brackish water, and innovations such as using depleted reservoir sections to store water to increase the use of recycled water. It was noted that brackish water resources need to be mapped and understood in greater detail. The objective is to use brackish water at a cost equal to, or less, than fresh water

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

New insights into oxidation behaviours of crude oils

Energy Technology Data Exchange (ETDEWEB)

Li, J.; Mehta, S.A.; Moore, R.G. [Calgary Univ., AB (Canada)

2006-07-01

Innovative technologies will be needed to develop many of the world's oil reservoirs in an economically sustainable manner. In recent years, air injection for light oil reservoirs has gained recognition as an Improved Oil Recovery (IOR) process. In this process, the oxygen from the injected air reacts with a small fraction of the reservoir oil at high temperature to produce a mixture of carbon dioxide and nitrogen. The produced gas generated by the reaction mobilizes the oil downstream, thereby sweeping oil towards the production wells. High pressure air injection used in light oil reservoirs differs from the process used in heavy oil reservoirs, despite the fact that various oxidation reaction schemes exist. The key challenge facing the air injection process is the complexity of the oxidation reaction for crude oil and the lack of understanding of the oxidation behavior of light oils. This study identified a range of oxidation behaviors between light oil and heavy oil. The relationship between crude oil composition and its oxidation behaviors was also examined with reference to 3 different oils and their SARA (saturates, aromatics, resins and asphaltenes) fractions. This study was carried out at various pressures and temperatures using thermogravimetry and pressurized differential scanning calorimetry (PDSC) as the thermal analysis techniques.