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Collaborating Authors
North America
Polymer Stabilized Foam Rheology and Stability for Unconventional EOR Application
Griffith, Christopher (Chevron) | Jin, Julia (Chevron) | Linnemeyer, Harry (Chevron) | Pinnawala, Gayani (Chevron) | Aminzadeh, Behdad (Chevron) | Lau, Samuel (Chevron) | Kim, Do Hoon (Chevron) | Alexis, Dennis (Chevron) | Malik, Taimur (Chevron) | Dwarakanath, Varadarajan (Chevron)
Abstract It has been shownthat injecting surfactants into unconventional hydraulically fractured wells can improve oil recovery. It is hypothesized that oil recovery can be further improved by more efficiently distributing surfactants into the reservoir using foam. The challenge is that in high temperature applications (e.g., 240 F) many of these formulations may not make stable foams as they have only moderate foaming properties (short half-life). Therefore, we are evaluating polymers that can be used to improve foam stability in high temperature wells which has the potential to improve oil recovery beyond surfactant only injection.Surfactant stabilized nitrogen foams were evaluated using a foam rheometer at pressures and temperatures representative of a field pilot well. The evaluation process consisted of measuring baseline properties (foam viscosity and stability) of a surfactant stabilized foam without any added stabilizer. Next, conventional enhanced oil recovery polymers (HPAMs, modified-HPAMs, and nonionic polymers) were added at different concentrations to determine their impacts on foam stability. Our results demonstrate that inclusion of a relatively low concentration (0.05 wt% – 0.2 wt%) of polymer has a pronounced impact on foam stability. It was determined that reservoir temperature plays a key role in selecting astabilizing polymer. For example, at higher temperatures (>240 F), sulfonated HPAM polymers at just 0.2 wt% more than doubled the stability of the foam. The polymer that was selected from this lab work was tested in a foam field trial in an unconventional well. It is thought that improved foam stability could potentially help improve the distribution of surfactants in fracture network and further improve oil recovery.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Abstract Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drop from the injection well to the polymer front may act as a pressure barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity (and even sweep efficiency in some cases). This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Both analytical and numerical methods are used to address this issue. We examine the relevance of the pressure barrier concept for a wide variety of circumstances, including oil viscosities ranging from 10-cp (like at Daqing, China) to 1650-cp (like at Pelican Lake, Alberta), vertical wells (like at Tambaredjo, Suriname) versus horizontal wells (like at Milne Point, Alaska), single versus multiple layered reservoirs, permeability contrast, and with versus with crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multi-zoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors (like fracture extension) intervene. For multi-zoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. The relevance of our findings is applied to operations for several existing polymer floods. This work is particularly relevant to viscous-oil reservoirs (like Pelican Lake and others) where the injected polymer viscosities are substantially lower than the oil viscosity
- North America > Canada > Alberta (0.89)
- North America > United States > Texas (0.68)
- Asia > China > Heilongjiang Province > Daqing (0.26)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- (5 more...)
Re-Injection of Produced Polymer in EOR Projects to Improve Economics and Reduce Carbon Footprint
Ghosh, Pinaki (SNF Holding Company) | Wilton, Ryan R (SNF Holding Company) | Bowers, Annalise (SNF Holding Company) | O’Brien, Thomas (SNF Holding Company) | Cao, Yu (SNF Holding Company) | Wilson, Clayton (SNF Holding Company) | Metidji, Mahmoud Ould (SNF SA) | Dupuis, Guillaume (SNF SA) | Ravikiran, Ravi (SNF Holding Company)
Abstract Chemical Enhanced Oil Recovery (cEOR) flooding is one of the more attractive methods to improve oil recovery. However, during times of instability in the oil market, cost of specialized chemicals and necessary facilities for alkali-surfactant-polymer (ASP) or surfactant-polymer (SP) make this technology very expensive and challenging to implement in the field. In majority of cases, polymer flooding alone has proven to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, challenging economic environment has operators looking for added economic and sustainable savings. The possibility of re-injection of produced polymer to offset injection concentration requirements can lead to reduced cost and longer sustainability of oil recovery; thus, offering a subsequent reduction in produced water treatment and a reduced full-cycle carbon footprint. This innovative approach is subject to conditions experienced in the surface facilities, as well as in the reservoir. As part of this study, different polymer chemistries were investigated for their mobility control in porous media and comparative effect on oil recovery trends in presence of produced fluid containing residual polymer. The initial fluid-fluid testing and lab characterization results were validated against a mature field EOR project for reduction in polymer requirement to achieve target viscosity. Monophasic flow behavior experiments were performed in Bentheimer and Berea outcrop cores, while oil recovery experiments were performed in Bentheimer outcrops with different polymer solutions – freshly made and combinations with residual produced polymer. In addition, comparative injectivity experiments with field and lab prepared solutions were performed in Bentheimer outcrop cores. Based on field observations and lab measurements, a 10-15% reduction in fresh polymer loading could be achieved through the re-utilization of water containing residual polymer in these specific field conditions. Similar screen factor measurements were obtained with increasing concentration of residual polymer solution. This agreed with the monophasic injectivity experiments in both outcrop cores that resulted in similar resistance factors for fresh polymer and blends with produced water containing residual polymer solution. Oil recovery experiments also resulted in similar oil displacement behavior (approximately 30-40% OOIP after 0.5 PV waterflood) for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10-15% polymer loading reduction.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada (0.93)
- Europe (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Lloydminster Field (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P09C License > Horizon Field > Vlieland Sandstone Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Polymer Selection for Sandstone Reservoirs Using Heterogeneous Micromodels, Field Flow Fractionation and Corefloods
Borovina, Ante (OMV Exploration & Production GmbH) | Reina, Rafael E. Hincapie (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH) | Hoffmann, Eugen (HOT Microfluidics GmbH) | Wegner, Jonas (HOT Microfluidics GmbH) | Steindl, Johannes (OMV Exploration & Production GmbH)
Abstract Incremental oil recovery due to polymer flooding results from acceleration of oil production along flow paths and improving sweep efficiency. To achieve favorable economics, polymers should have a high viscosifying power and low adsorption. However, in addition, incremental oil production from various rock qualities needs to be maximized. We developed a workflow using a layered micromodel, corefloods and Field-Flow Fractionation (FFF) to determine the Molecular Weight Distribution (MWD) for the selection of polymers addressing heterogeneous reservoirs. We have designed micromodels consisting of two layers with different permeabilities, one four times larger than the other. The micromodel structure is based on the characteristics of a real sandstone core, with the dimensions 6 cm × 2 cm. These micromodels were used as preliminary screening of the polymers incorporating heterogeneity effects. Subsequently, single- and two-phase core experiments were performed to determine injectivity effects and displacement efficiency of the selected polymers. In addition, FFF was used to measure the molecular weight distribution, gyration radii and conformance of the polymers. Based on the workflow a polymer was selected. All polymers were tested at target viscosity at 7 1/s shear rate. Micromodel experiments showed that tested polymers are leading to improved sweep efficiency of heterogeneous structure. The displacement efficiency within the higher permeable layer was similar for the investigated polymers whereas the oil recovery from the lower permeable layer showed differences. FFF revealed that the MWD's of the tested polymers were different. The MWD of one of the polymers showed a large number of larger molecules compared with the other polymers. This polymer did not lead to the highest oil recovery in the micromodel. Injectivity and propagation of the higher MW polymer in both single- and two-phase core-floods was falling behind the other polymers. Measurements of the MWD of the core effluent showed that for all tested polymers the larger molecules are initially retained more than the smaller molecules. The polymer with the smallest molecules and narrow MWD showed the best propagation characteristics in the core. Owing to the good performance of this polymer in terms of sweep efficiency improvement, injectivity, and propagation, this polymer was selected for a field application. Therefore, the novelty presented here can be summarised as follow: Heterogeneous micromodels were used to screen polymers for one-dimensional displacement efficiency and sweep efficiency effects Single- and two-phase core floods in combination with Field-Flow Fractionation revealed the impact of the molecular weight distribution (MWD) on polymer injectivity, propagation and retention Selection of polymers need to include MWD to find the most effective polymer Polymer selection needs to take near-wellbore and reservoir effects (micro- and sweep efficiency in heterogeneous reservoirs) into account
- Europe (1.00)
- Asia (1.00)
- North America > United States > California (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (3 more...)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Measurement while drilling (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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Use of Horizontal Injectors for Improving Injectivity and Conformance in Polymer Floods
Hwang, Jongsoo (The University of Texas Austin) | Zheng, Shuang (The University of Texas Austin) | Sharma, Mukul (The University of Texas Austin) | Chiotoroiu, Maria-Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH)
Abstract Several field cases have demonstrated polymer injection in a horizontal well increases oil recovery. It is important to maintain high injectivity while preventing injection-induced fractures to ensure good reservoir sweep. Our primary goal in this paper is to better understand polymer injection data from horizontal injectors in the Matzen field using a fully integrated reservoir, geomechanics, and fracturing model. By simulating polymer injection history, we present several advantages of horizontal injectors over the vertical wells. Horizontal injectors delay fracture initiation and provide better tolerance to polymer plugging on the wellbore surface. Simulations explain the measured PLT data of fluid distributions influenced by accumulated polymer deposition in multiple zones. We show that gradual injectivity decline is attributed to both polymer filter cake buildup and high-viscosity, shear-thickening zones created around the wellbore. The field case simulation also clarifies the flow distribution in different sands and how polymer rheology affects this. This distribution is found to be different than for water injection. Results from periodic acid treatments clearly show that free-flowing particles in the polymer solution are responsible for formation damage. Polymer plugging and the viscous pressure drop in the shear-thickening zone are the primary factor affecting the measured injection pressure. Based on the strong near-wellbore viscosity impact, geomechanical simulations identify reservoir zones prone to fracture growth during long-term injection, and we suggest strategies to avoid injection induced fractures that can lead to poor conformance.
- Europe (1.00)
- North America > United States > Alaska (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.51)
- 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)
- (37 more...)
Abstract Polymer flooding is now a well-recognised and mature technology to increase hydrocarbon recovery, used in many parts of the world. Given its success, operators are looking at new opportunities for polymer and are trying to push the technical barriers even further. One of these barriers is high salinity which is detrimental to the economics of polymer floods with standard polymers, and thus requires other solutions. Associative polymers are polyacrylamide-based polymers well known for their good resistance to high salinity due to their structure and as a result they could be very promising for use in fields with high TDS. However, they have so far seen little use in field applications due to their perceived plugging tendency, high permeability and mobility reduction which make them more adapted to near-wellbore treatment. Most if not all of the field projects involving associative polymers have taken place in China and in Canada, but little has been published so far. Since public information is available for the Canadian projects, the aim of this paper is to present the field experience of associative polymers in these Canadian projects. The paper will focus on presenting four field cases, Bodo, Mooney and Suffield (2), all in Western Canada. Bodo is a polymer flood while Mooney and Suffield are both polymer and alkali-surfactant polymer projects. Although public information is not always complete, what is available provides some useful and much needed insight on the performances of associative polymers in the field. Our analysis of these four field cases suggests that associative polymers can be injected without special difficulty provided they are well chosen, that is they need to be sufficiently associative to outperform HPAM but not too much in order not to plug the reservoir. These results should comfort engineers who have so far been reluctant to use associative polymers due to lack of field experience. Very few field cases of polymer flood involving associative polymers have been published so far and this paper attempts to shed some light on the performances of associative polymer in some unpublished projects. These positive results may incite engineers working on projects where associative polymers could find a use to consider them.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.71)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.46)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Suffield Block > Suffield Field > Aecog (E) F-4 Suff 7-27-17-5 Well (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Mooney Field > Bluesky Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Bluesky Formation (0.99)
- Africa > Nigeria > Gulf of Guinea > Rivers > Niger Delta > Niger Delta Basin > OML 11 > Bodo Field (0.99)
Abstract This paper discusses surfactant, co-solvent, alkali and polymer (ASP) formulations developed for the Kuparuk Field in Alaska. This field is a mature conventional reservoir that exhibits favorable characteristics for surfactant flooding. The formulations have been tested in the laboratory and in the field with good results. In core floods with live oil and reservoir core, oil saturation has been driven below 5% (Sorc) recovering more than 90% of the waterflood residual oil (Sorw). An ASP treatment, via a single well chemical tracer test, has yielded an Sorc of 1% recovering 96% of the Sorw in the field. However, the process of developing ASP formulations that effectively recover residual oil and represents a commercially viable ASP flood has been challenging. Driving the surfactant retention to low values has required the use of enhanced alkoxylated surfactants and co-solvents that provide low interfacial tension (IFT) micro-emulsions with low viscosity under broad salinity ranges. Kuparuk's rock mineralogy has also played an important role due its heterogeneity and high clay content. Clays with iron bearing minerals and significant ionic exchange have required a systematic study to better understand the effect of reservoir rock on the surfactant treatment. The impact of calcium and magnesium released by the reservoir rock was of primary concern. Significant results from the Kuparuk ASP formulation study are summarized. The performance of formulation components and their overall effect on surfactant retention, as well as rock mineralogy, are analyzed in detail. Experimental methodologies, analytical studies, and adequate core flood practices used to overcome challenges are also discussed. The lessons learned from this study have the potential to be used in other Alaskan fields, unlocking vast and valuable resources from mature reservoirs as well as new discoveries.
- Geology > Mineral > Silicate (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Geological Subdiscipline > Mineralogy (0.45)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Illinois > Loudon Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field > Kuparuk Formation (0.96)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.89)
X-Ray CT Investigation of Displacement Mechanisms for Heavy Oil Recovery by Low Concentration HPAM Polymers
Skauge, Arne (University of Bergen) | Shaker Shiran, Behruz (NORCE Energy) | Ormehaug, Per Arne (NORCE Energy) | Santanach Carreras, Enric (TOTAL E&P) | Klimenko, Alexandra (TOTAL E&P) | Levitt, David (TOTAL E&P)
Abstract Polymer flooding has proved to be a successful EOR method in very heavy oil reservoirs, despite failure to achieve a favorable mobility ratio even with polymer, which was originally imagined to be a necessary criterion for success based upon fractional flow theory. In a previous study (Levitt et al. 2013), we demonstrated a surprisingly high oil recovery with low concentration (and viscosity) partially hydrolyzed polyacrylamide (HPAM) polymer solutions of only 3 cP displacing a 2000 cP oil. Additional experiments with more viscous as well as non-elastic viscosifying agents demonstrated that recovery is not sensitive to viscosity, and thus cannot be understood through fractional flow theory. The scope of this paper is to understand where additional recovery comes from through visualization using CT imaging, in order to allow operative driving mechanisms to be optimized. Two long core (30 cm) flooding experiments have been performed to understand oil recovery at adverse mobility ratio. The first experiment started with waterflooding followed with polymer flooding (3 cP), while the second experiment started with polymer flooding directly. In-situ saturations were obtained by a medical CT scanner operated at high energy level, and used two X-ray sources and two array detectors simultaneously. The procedure was to perform the waterflood or polymer flood direct in the CT scanner. That will give us the finger development from early stage until a well-established channel is developed. The frontal velocity was about 1 ft/day. The displacements were further analyzed through simulations and dynamic pore scale model to understand the changes in fluid flow. CT imaging demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density. This is in agreement with observed behavior of unstable displacements involving viscoelastic fluids in Hele-Shaw cells (Bonn et al., 1995). These results suggest that elasticity may be more significant than viscosity in optimizing oil recovery under highly unstable conditions, for example with oils of ~1000 cP or higher. Presence of fingering under both water and polymer flood was also confirmed, with dominant finger diameter on the order of 1 mm (under waterflood) to 2 mm (under polymer flood). Fingers grow in thickness and length, and near the inlet they start quickly to overlap. Fingers are formed mostly in the middle of the core and fewer fingers appear near the wall of the core. CT shows that the waterflood is dominated by viscous fingering. Experimental CT data together with simulations and pore scale modelling have demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density or stabilization of the displacement front. Among other things, these results demonstrate that the assumption of capillary equilibrium is inappropriate under these conditions, and thus that fractional flow theory is poorly suited to predicting or optimizing recovery.
- Europe (1.00)
- Asia (0.94)
- North America > United States > Oklahoma (0.28)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Numerical Simulation of Crossed-Linked Polymer Injection in Dina Cretaceous Field: A Real Field Case Study
Izadi, Mehdi (Ecopetrol SA) | Jimenez, Jaime Alberto (Ecopetrol SA) | Zapata, Jose Francisco (Ecopetrol SA) | Felipe Castillo, Andres (Ecopetrol) | Pinto, John (Ecopetrol SA) | Vicente, Sebastian (Ecopetrol SA)
Abstract The main objective of this work is to shed light on the mechanism of modeling crossed-linked polymer (CLP) technology, by incorporating real field pilot injection and production data in the Dina Cretaceous field located in the Upper Magdalena Valley (UMV) Basin in Colombia. The paper will highlight why original simulation model predictions differ from the actual observed field data and the predictability of numerical simulation of CEOR process would be discussed and presented. Despite successful application and positive field results in the literature, the propagation of CLP system in porous media has been challenged with conflicting opinions and reports and still remains debatable and uncertain. This paper will use recent experimental laboratory data in conjunction with actual field data to properly explain the possible mechanism of CLP and offer practical modeling techniques to capture experimental and field data. Therefore a modeling methodology was developed and used to model the field data, this method is based on previous modeling mechanisms with incorporating a new grid-based residual resistance factor (RRF) and pore throat sizes. The model requires a proper understanding of rock typing and populate the permeability distribution based on pore throat sizes. The new modeling mechanism was able to reasonably predict the pilot performance in some of the offset producers. To model delayed viscosification and adsorption of the CLP process, two approaches has been evaluated and used in the original simulation model, the use of multiple regions and chemical reaction. The chemical reaction rate is tuned to calibrate laboratory data and to model the delayed viscosification and RRF. However recent laboratory experiments explained the possible mechanisms of CLP formation through intra-molecular crosslinking and intra-inter-molecular crosslinking. In conclusion, because of extensive and numerous laboratory experiments and the conduct of field pilot results, proposed numerical modeling demonstrate the complexity of modeling the CLP system and offers a practical solution to the field applications.
- South America > Colombia (0.68)
- Europe > United Kingdom > North Sea > Central North Sea (0.45)
- North America > United States > Oklahoma (0.29)
- South America > Colombia > Huila Department > Dina Field (0.99)
- North America > United States > Oklahoma > Anadarko Basin > North Burbank Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (2 more...)
Abstract This paper introduces a new approach for using solvents for enhanced oil recovery from organic-rich unconventional reservoirs. The heavy organic components in the reservoir rock, i.e. bitumen, are included in the phase behavior model using a cubic equation-of-state. The phase behavior of mixtures of methane, CO2, and dimethyl ether (DME) with reservoir hydrocarbons including bitumen was studied to better understand the interaction of each solvent with reservoir fluids including water in the case of DME. The phase behavior models were then used in an equation-of-state compositional reservoir simulator to explore the potential of each solvent to increase the oil recovery including otherwise immobile bitumen from a 3D heterogeneous reservoir.
- 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)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (2 more...)