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Collaborating Authors
Improved and Enhanced Recovery
Summary Oil and water production data are regularly measured in oilfield operations and vary from well to well and change with time. Theoretical models are often used to establish the production expectation for different recovery processes. A performance surveillance understanding can be developed by comparing the field production data with the production expectation. This comparison generates quantitative or qualitative signals to determine whether the producer meets production expectations or the producer is underperforming and appropriate operational action is required to address the underperformance. The case study is for the South Belridge diatomite in California. This hydraulically fractured diatomite reservoir is currently under waterflood and steamflood. A methodology is proposed to establish the production expectation from historical production data. For primary depletion, the formation linear and bilinear flow models are applied to producers with vertical hydraulic fractures. For waterflood, an analytical method derived from the Buckley-Leverett displacement theory is used. Those analytical methods can predict production and provide surveillance signals for producers in the primary and waterflood recovery stages. For steamflood, a semiquantitative performance/surveillance criterion is proposed on the basis of understanding the mechanistic oil banking concept and reservoir simulation results for steamflood and waterflood. With those models representing expected production performance, an integrated flow regime diagram is proposed for production surveillance. A performance expectation can be developed for an individual producer. A significant overperformance relative to the expectation normally indicates changes in the recovery mechanism or improvement in sweep efficiency. A significant underperformance usually signifies an operational issue that requires correction to optimize the production performance. In the case study, the surveillance methodology for producers under primary depletion, waterflood, or steamflood is demonstrated by use of historical production data. In addition, water channeling between injectors and producers and its impact on production performance are discussed. On the basis of this surveillance methodology, some operational actions were proposed, and successful results are demonstrated. Examples of forecast for an individual producer in the primary depletion stage and field scale prediction in the waterflood stage are provided. Application indicates that the proposed methodology can serve as a convenient and practical tool for reservoir surveillance and operational optimization.
- North America > United States > California > San Joaquin Basin > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Diatomite Formation (0.99)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > Belridge Field > Tulare Formation (0.98)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > Belridge Field > Diatomite Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production data management (1.00)
Qualitative and Quantitative Analyses of the Three-Phase Distribution of Oil, Water, and Gas in Bentheimer Sandstone by Use of Micro-CT Imaging
Feali, M.. (University of New South Wales) | Pinczewski, W.V.. V. (University of New South Wales) | Cinar, Y.. (University of New South Wales) | Arns, C.H.. H. (University of New South Wales) | Arns, J.-Y.. -Y. (University of New South Wales) | Turner, M.. (Australian National University) | Senden, T.. (Australian National University) | Francois, N.. (Australian National University) | Knackstedt, M.. (Digitalcore)
Summary It is now widely acknowledged that continuous oil-spreading films observed in 2D glass-micromodel studies for strongly water-wet three-phase oil, water, and gas systems are also present in real porous media, and they result in lower tertiary-gasflood residual oil saturations than for corresponding negative spreading systems that do not display oil-spreading behavior. However, it has not yet been possible to directly confirm the presence of continuous spreading films in real porous media in three dimensions, and little is understood of the distribution of the phases within the complex geometry and topology of actual porous media for different spreading conditions. This paper describes a study with high-resolution X-ray microtomography to image the distribution of oil, water, and gas after tertiary gasflooding to recover waterflood residual oil for two sets of fluids, one positive spreading and the other negative spreading, in strongly water-wet Bentheimer sandstone. We show that, for the positive spreading system, oil-spreading films maintain the connectivity of the oil phase down to low oil saturation. At similar oil saturation, no oil films are observed for the negative spreading system, and the oil phase is disconnected. The spatial continuity of the oil-spreading films over the imaged volume is confirmed by the computed Euler characteristic for the oil phase.
- Asia > Middle East (0.93)
- North America > United States > Texas (0.29)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Reservoir Simulation of Steam Fracturing in Early-Cycle Cyclic Steam Stimulation
Cokar, Marya (Department of Chemical and Petroleum Engineering, Schulich School of Engineering, University of Calgary) | Kallos, Michael S. (Department of Chemical and Petroleum Engineering, Schulich School of Engineering, University of Calgary) | Gates, Ian D. (Department of Chemical and Petroleum Engineering, Schulich School of Engineering, University of Calgary)
Summary In cyclic steam stimulation (CSS), steam is injected above the fracture pressure into the oil-sands reservoir. In early cycles, the injected steam fractures the reservoir, creating a relatively thin dilated zone that allows rapid distribution of heat within the reservoir without excessive displacement of oil from the neighborhood of the wellbore. Numerical reservoir-simulation models of CSS that deal with the fracturing process have difficulty simultaneously capturing flowing bottomhole-pressure (BHP) behavior and steam injection rate. In this research, coupled reservoir-simulation (flow and heat transfer) and geomechanics models are investigated to model dynamic fracturing during the first cycle of CSS in an oil-sands reservoir. In Alberta, Canada, in terms of volumetric production rate, CSS is the largest thermal recovery technology for bitumen production, with production rates equal to approximately 1.3 million B/D in 2008. The average recovery factor from CSS is between 25 and 28% at the economic end of the process. This implies that the majority of bitumen remains in the ground. Because the mobility of the bitumen depends strongly on temperature, the performance of CSS is intimately linked to steam conformance in the reservoir, which is largely established during steam fracturing of the reservoir in the early cycles of the process. Thus, a fundamental understanding of the flow and geomechanical aspects of early-cycle CSS is critical. A detailed thermal reservoir-simulation model, including dilation and dynamic fracturing, was developed, with the use of a commercially available thermal reservoir simulator, to understand their effects on BHP and injection rate. The results demonstrate that geomechanics must be included to accurately model CSS. The results also suggest that the reservoir dilates during steam injection as the result of increases in reservoir temperature, which lead to thermal dilation and higher pore pressure.
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > British Columbia > Peace River Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Primrose Field > Clearwater Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Summary For ultratight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. This paper is a third-phase study of the use of surfactant imbibition to increase oil recovery from Bakken shale. The surfactant formulations that we used in this paper are the initial results that are based on our previous study, in which a group of surfactant formulations was examined—balancing the temperature, pH, salinity, and divalent-cation content of aqueous fluids to increase oil production from shale with ultralow porosity and permeability in the Middle Member of the Bakken formation in the Williston basin of North Dakota. In our previous study, through the use of spontaneous imbibition, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed in which brine and surfactant (0.05 to 0.2 wt% concentration) imbibition yielded recovery values of 1.55 to 76% original oil in place (OOIP) at high salinity (150 to 300 g/L; 15 to 30 wt%) and temperatures ranging from 23 to 120°C. To advance this work, this paper determines the wettability of different parts of the Bakken formation. One goal of this research is to identify whether the wettability can be altered by means of surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale and to examine the viability of a field application. In this paper, through the use of modified Amott-Harvey tests, the wettability was determined for cores and slices from three wells at different portions of the Bakken formation. The tests were performed under reservoir conditions (90 to 120°C, 150- to 300-g/L formation-water salinity), with the use of Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction of the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided enhanced-oil-recovery [(EOR) vs. brine water imbibition alone] values of 6.8 to 10.2% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.6 to 25.4% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken formation. Positive results were generally observed with all four surfactants: amphoteric dimethyl amine oxide, nonionic ethoxylated alcohol, anionic internal olefin sulfonate, and anionic linear α-olefin sulfonate. From our work to date, no definitive correlation is evident in surfactant effectiveness vs. temperature, core porosity, core source (i.e., Upper Shale or the Middle Member), or core preservation (sealed) or cleaning before use.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (6 more...)
Summary Steam-assisted gravity drainage (SAGD) is the primary in-situ recovery method for bitumen from the large Athabasca deposit in Alberta, Canada. SAGD field operations encounter a significant decrease in production performance when low-permeability shale barriers are present in the formation. These layers can reduce SAGD performance and impede the growth of the steam chamber. They also significantly limit the percentage of the deposit from which bitumen can be economically recovered with SAGD. The concept of drilling vertical slimholes to create flow paths through barriers was conceived and investigated at Alberta Innovates-Technology Futures (AITF), formerly the Alberta Research Council. The use of slimholes has the potential to significantly increase the amount of recoverable bitumen (reserves) and the rate at which it is produced during SAGD. For shallow reservoirs, the slimholes could be drilled from the surface at a relatively low cost. It is believed that the process can be economically viable after its technical operation has been optimized with improvements in drilling technology, slimhole size and spacing, and enhanced usage of the slimholes in the development of steam chambers above the shale layers. Alternatively, the slimholes could be drilled from the horizontal wellbores (to avoid surface disturbance) as either horizontal slimholes from the producer or as horizontal/vertical slimhole combinations from the injector. The 2D and 3D field-scale numerical simulations were performed by use of reservoir properties and operating conditions based on published information for the MacKay River SAGD operation in the Athabasca deposit. The reservoir depth was 135 m, the initial pressure 500 kPaa, the initial temperature 7.5°C, and the initial oil saturation (SO) 0.8. The simulations explored the effect of vertical slimholes, which were laterally offset 7 m from the horizontal well-pair in reservoirs with and without shale layers or shale lenses. The effects on SAGD performance that were investigated were slimhole cross section (25 cm × 25 cm or 50 cm × 50 cm), the distance between slimholes (12 or 24 m) in the direction parallel to the well pair, the permeability of the reservoir and the vertical slimholes, and horizontal slimholes from the injector or producer. The slimhole cross section represents the disturbed area adjacent to the drilled slimhole and the drilled hole itself and is therefore relatively large. The slimholes were represented as high-permeability vertical channels by use of refined grids. For a reservoir with a continuous shale layer, SAGD performance was improved by vertical slimholes because of the recovery of previously inaccessible oil from above the shale layer, where a secondary steam chamber was formed.
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Greater Stella Area > Block 30/6a > Stella Field > Stella Ekofisk Formation > A2 Well (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Greater Stella Area > Block 30/6a > Stella Field > Stella Andrew Formation > A2 Well (0.99)
- (4 more...)
Summary Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil-producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work. Observations and conclusions include the following: Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been applied successfully to reservoirs with oil gravity as high as 41° API and as low as 16° API. When microbial growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm total dissolved solids (TDS). MEOR can be applied successfully in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always observed when treating producing wells. MEOR can be applied to many more reservoirs than thought originallys with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.
- North America > Canada (1.00)
- Asia (1.00)
- North America > United States > Texas (0.68)
- North America > United States > California > Los Angeles County (0.28)
- North America > United States > California > Beverly Hills Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Mannville Formation (0.99)
- Asia > Indonesia > East Kalimantan > Kutei Basin > Mahakam Block > Handil Field (0.99)
- (6 more...)
A Pilot Carbon Dioxide Test, Hall-Gurney Field, Kansas
Willhite, G.P.. P. (University of Kansas) | Byrnes, A.P.. P. (Chesapeake Energy Corp.) | Dubois, M.K.. K. (IHR) | Pancake, R.E.. E. (LLC) | Tsau, J.-S.. -S. (Murfin Drilling Company) | Daniels, J.R.. R. (University of Kansas) | Flanders, W.A.. A. (Murfin Drilling Company)
Summary A pilot carbon dioxide (CO2) -miscible flood was initiated in the Lansing-Kansas City C formation in the Hall-Gurney Field, Russell County, Kansas. The reservoir zone is an oomoldic limestone located at a depth of approximately 2,900 ft. The pilot consisted of one CO2 injection well and three production wells. Continuous CO2 injection began in December 2003 and continued through June 2005, at which point 16.19 million lbm of CO2 had been injected into the pilot area. Injection was converted to water in June 2005 to reduce operating costs to a break-even level with the expectation that sufficient CO2 was injected to displace the oil bank to the production wells by water injection. By March 2010, 8,736 bbl of oil had been produced from the pilot. Production from wells to the northwest of the pilot region indicated that oil displaced by CO2 injection was produced from five wells outside of the pilot area, to the northwest. Approximately 19,166 bbl of incremental oil was estimated to have been produced from these wells as of March 2010. There was evidence of a directional permeability trend toward the northwest through the pilot region. The majority of the injected CO2 remained in the pilot region, which was maintained at or above the minimum miscibility pressure (MMP). Although the four-well pilot was uneconomical, the estimated oil recovery attributed to the CO2 flood is 27,902 bbl, which is equivalent to a gross CO2 usage of 4.8 Mcf/bbl.
- North America > United States > Kansas > Russell County (1.00)
- North America > United States > Kansas > Barton County (1.00)
- North America > United States > Missouri > Jackson County > Kansas City (0.24)
- Geophysics > Seismic Surveying (0.68)
- Geophysics > Borehole Geophysics (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- North America > United States > Oklahoma > Anadarko Basin > Postle Field (0.99)
- North America > United States > Kansas > Hall-Gurney Field (0.99)
- North America > Canada > Alberta > Doe Field > Altia 102 Doe 10-26-81-13 Well (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation > A1 Well (0.99)
Summary In waterfloods, the existence of highly conductive thief zones causes poor volumetric sweep efficiency, resulting in early breakthrough and excessive production of water. A conventional strategy of redirecting injection by closing off perforations yields short-term benefits because diversion occurs near the wellbore. As an alternative, temperature-triggered submicron polymers with low viscosity (popping agents), which give an opportunity for conformance control deep in the reservoir, have been introduced in recent years. This technology aids conformance control by plugging the high-permeability zones and diverting the fluid to the unswept portion of the reservoir. Understanding the critical parameters that lead to a successful treatment and accurate determination of the slug size are two important criteria for a technically and economically successful treatment. In this study, we first investigate the effect of different parameters on the success of a conformance control treatment. A comprehensive design-of-experiments (DOE) study resolves the effects (and combined effects) of kv/kh, treatment fluid concentration, thief-zone to matrix-permeability ratio, mobility ratio, and location of the placement in the reservoir. Next, a methodology is developed for accurate determination of the conformance slug size. The method is built on the temporal moment and residence time distribution analysis (RTDA) of interwell tracers. Dynamic flow- and storage-capacity curves are used to identify the optimum slug size. 3D thermal computer simulations show that thief-zone to matrix-permeability ratio and placement location of the polymer are the most important parameters that affect the success of a treatment. The most desirable setting is placement of the polymer deep in the reservoir, closer to the producer within high kv/kh reservoirs. Furthermore, the computer simulations confirm the power of the new technique for optimal slug-size determination. This new technique can avoid underestimation of the volume that must be treated, which is critical for the success of a treatment.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Salema Field (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field
Pathak, Prabodh (ExxonMobil Production Company) | Fitz, Dale E. (ExxonMobil Exploration Company) | Babcock, Kenneth P. (ExxonMobil Production Company) | Wachtman, Richard J. (ExxonMobil Production Company)
Summary The technical success of an enhanced oil recovery (EOR) project depends on two main factors: first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters must be estimated before embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil. There are many methods for determining the oil saturation (Chang et al. 1988; Pathak et al. 1989), and these include core analysis, well-log analysis, log/inject/log (LIL) procedures (Richardson et al. 1973; Reedy 1984), and single-well chemical tracer tests (SWCTT) (Deans and Carlisle 1986). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. No single method achieves the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place (OIP) is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the ROS in the reservoir. This paper presents the results from a fieldwide data acquisition program conducted in a west Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in west Texas has been producing for more than the past 75 years, and the producing mechanisms have included primary recovery, secondary waterflooding, and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process, and it was imperative to evaluate the oil saturation in the lower, previously undeveloped zones. This paper briefly outlines the production history, reservoir description, and reservoir management of the Means field, but this paper concentrates on the residual oil zone (ROZ) that underlies the main producing zone (MPZ) and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS: core analysis, LIL tests, and SWCTT tests.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.93)
- Geology > Geological Subdiscipline (0.67)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- (6 more...)
Air-Foam-Injection Process: An Improved-Oil-Recovery Technique for Waterflooded Light-Oil Reservoirs
Dong, X.. (China University of Petroleum (Beijing)) | Liu, H.. (China University of Petroleum (Beijing)) | Sun, P.. (China University of Petroleum (Beijing)) | Zheng, J.. (Jidong Oilfield Company, China National Petroleum Corporation) | Sun, R.. (Jidong Oilfield Company, China National Petroleum Corporation)
Summary With the intent of solving problems that emerge at the later stage of waterflooded reservoirs, we study the feasibility of air-foam flooding of waterflooded light-oil reservoirs using the method of physical simulation. Through isothermal combustion experiments, the influence of clay mineral and foam on low-temperature-oxidation (LTO) reactions is investigated qualitatively. Then, the quantitative investigation of water saturation on oxidation rate and O2 consumption rate is discussed. After that, some dynamic foam displacement experiments are also performed, including the singletube displacement experiments of air foam at different water saturations and enhanced-oil-recovery (EOR) experiments of air-foam flooding in parallel tubes. In addition, in order to verify the O2 consumption capacity of the sample oil, a slimtube experiment is conducted. The results show that the presence of clay minerals could speed the process of the LTO reaction, while the presence of foam will slow this process. The LTO reaction is not significantly associated with oil viscosity. The concentration of O2 was near zero when the gas breakthrough occurred. Once the oxidation region reached the outlet, the concentration of O2 suddenly increased, and the effect of O2 consumption became worse. G64-38 crude oil performs better in the process of O2 consumption. The injection of air foam could effectively plug the high-permeability tube and restart the low-permeability tube. This paper could be used as a tool for the successful design of air-foam flooding at a later waterflood stage to enhance crude-oil recovery in light-oil reservoirs.
- Europe (1.00)
- Asia > China (1.00)
- North America > United States > Louisiana (0.67)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.81)
- Geology > Mineral > Silicate > Phyllosilicate (0.70)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.46)
- South America > Argentina > Mendoza > Cuyana Basin > Barrancas Field (0.99)
- Oceania > Australia > South Australia > Eromanga Basin (0.99)
- Oceania > Australia > Queensland > Eromanga Basin (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)