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Collaborating Authors
Koh, Heesong
Surfactant Enhanced Waterflood SEW in Medium and Light Crude Oil Reservoirs
Quintero, Lirio (Baker Hughes, a GE Company) | Deighton, Michael (Baker Hughes, a GE Company) | Nguyen, Henry (Baker Hughes, a GE Company) | Willmott, Eric (Baker Hughes, a GE Company) | Kuznetsov, Oleksandr V. (Baker Hughes, a GE Company) | Tompkins, Rose (Baker Hughes, a GE Company) | Koh, Heesong (Baker Hughes, a GE Company)
Abstract Combinations of surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) have proven, in the laboratory and the field, to be good methods for enhanced oil recovery (EOR). However, field implementation of these methods has not been widely materialized because of economics, especially at the recent crude oil prices. A more economical EOR alternative is surfactant-enhanced waterflood (SEW), achieved by injecting a small amount of an appropriate surfactant with the injected water. This method could be applied in reservoirs containing medium and light crude oil (less than 5 cP viscosity at reservoir temperature) that are currently under waterflood, and has the economic advantage of minimal additional CAPEX investment for surface facilities. The main target of this method is to mobilize residual oil trapped at pore throats after an extensive waterflood. Increasing the Ca improves the efficiency of crude oil displacement from injectors to producers. The workflow of surfactant formulation selection involves a comprehensive sequence of studies that cover: Selection of candidate surfactants based on reservoir fluids properties and reservoir data conditions, Winsor systems phase behavior studies, IFT measurement, Evaluation of surfactant adsorption, and Evaluation of the formulation in porous media (sandpack and coreflood tests). Parameters involved in the phase behavior studies included a broad range of salinity, hardness, temperature, surfactants ratio in blends, and the equivalent carbon number (EACN) of the evaluated crude oils. After screening and selecting formulations, waterflood simulation with the surfactant formulation is required to estimate the recovery factor, the production profile, and the economics of the project. Optimal surfactant formulations determined by phase behavior studies using surfactants-brine-crude oil systems were obtained for selected reservoir conditions (temperature, injection water salinity, specific crude oils, and rock properties). These custom-made formulations were Winsor III microemulsions with very high oil solubilization, and an IFT equal to or lower than 10 mN/m. Evaluation of the selected formulations at low surfactant concentrations (around 0.15% in injection water) in sandpack and coreflood tests resulted in approximately 30% additional oil recovery. The results demonstrate that a high percentage of additional oil could be recovered after waterflood by adding a small concentration of a properly selected surfactant formulation to the water injected into cores saturated with light crude oil. This paper discusses some aspects of the experimental work involved in various phases of the process for selecting surfactant formulations that meet the requirements of ultra-low IFT that result in a high capillary number (Ca) and high recovery of low-viscosity residual medium and/or light crude oil left behind in reservoirs that have been produced by waterflood.
- Geology > Geological Subdiscipline > Geomechanics (0.54)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Summary Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, and hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation (ROS), to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the waterfloods, with up to 24% lower oil saturation after the polymer flood than after the waterflood. The experimental data are in good agreement with the fractional-flow analysis by use of the assumptions that the true ROSs and endpoint relative permeabilities are the same for both water and polymer. This suggests that, for more-viscous oils, the oil saturation at the end of a waterflood (i.e., at greater than 99% water cut) is better described as “remaining” oil saturation rather than the true “residual” oil saturation. This was true for all the corefloods, regardless of the core permeability and without the need for assuming a permeability-reduction factor in the fractional-flow analysis.
- Asia (1.00)
- North America > United States > Texas (0.47)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary Water-based polymers are often used to improve oil recovery by increasing sweep efficiency. However, recent laboratory and field work have suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation (ROS). The objective of this work is to investigate the effect of viscoelastic polymers on ROS in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120 cp) and then waterflooded to ROS with brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM). Significant reduction in residual oil was observed for all corefloods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number, NDe). An average residual-oil reduction of 5% original oil in place (OOIP) was found during HPAM polymer floods for NDe of 0.6 to 25. HPAM floods with very-low elasticity (NDe < 0.6) did not result in observable reduction in ROS; however, another 10% OOIP residual oil was reduced when the flow rate was increased (NDe > 25). All experiments at constant pressure drop indicate that polymer viscoelasticity reduces the ROS. Results from computed-tomography (CT) scans further support these observations. A correlation between Deborah number and ROS is also presented.
- Asia > China > Heilongjiang Province (0.46)
- North America > United States > Texas (0.30)
- North America > United States > Louisiana (0.28)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > University Field > Wolfcamp Formation (0.94)
Reduction of Residual Oil Saturation in Sandstone Cores Using Viscoelastic Polymers
Qi, Pengpeng (The University of Texas at Austin) | Ehrenfried, Daniel H. (The University of Texas at Austin) | Koh, Heesong (The University of Texas at Austin) | Balhoff, Matthew T. (The University of Texas at Austin)
Abstract Water-based polymers are often used to improve oil recovery by increasing displacement sweep efficiency. However, recent laboratory and field work has suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation. The objective of this work is to investigate the effect of viscoelastic polymers on residual oil saturation in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120cp) and then waterflooded to residual oil saturation using brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM). Significant reduction in residual oil was observed for all core floods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number, NDe). An average residual oil reduction of 5% OOIP was found during HPAM polymer floods for NDe of 0.6 to 25. HPAM floods with very low elasticity (NDe<0.6) did not result in observable reduction in residual oil saturation; however, another 10% OOIP residual oil was reduced when the flow rate was increased (NDe>25). All experiments at constant pressure drop indicate polymer viscoelasticity reduces the residual oil saturation. Results from CT scans further support these observations. A correlation between Deborah number and residual oil saturation is also presented.
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, For this application, hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. In an era of low cost oil, it is becoming even more essential to optimize the polymer flooding design under realistic reservoir conditions. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation, in order to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the water floods, with up to 24% lower oil saturation after the polymer flood than the water flood. The experimental data are in good agreement with the fractional flow analysis using the assumptions that the true residual oil saturations and end point relative permeabilities are the same for both water and polymer. This suggests that for more viscous oils, the oil saturation at the end of water flood (i.e. at greater than 99% water cut) is better described as ‘emaining’ oil saturation rather than the true ‘esidual’ oil saturation. This was true for all of the corefloods regardless of the core permeability and without the need for assuming a permeability reduction factor in the fractional flow analysis.
- Asia (0.68)
- North America > United States > Louisiana (0.28)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Mechanistic Simulation of Residual Oil Saturation in Viscoelastic Polymer Floods
Lotfollahi, Mohammad (The University of Texas at Austin) | Koh, Heesong (The University of Texas at Austin) | Li, Zhitao (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract Polymer flooding is one of the most widely used enhanced oil recovery methods due to its good performance in numerous large commercial field projects and its relative simplicity and low cost compared to most other enhance oil recovery methods. The main mechanism is considered to be improved sweep efficiency, but numerous studies have also reported lower residual oil saturation to polymer than to water. Because the results depend on many variables such as the initial oil saturation, rock characteristics and polymer characteristics, such experiments must be performed at reservoir conditions and at controlled capillary numbers and so forth to measure the reduction that applies to field polymer floods. Furthermore, a mechanistic model is needed to scale up the laboratory coreflood results to the field. We implemented and tested the new model for the residual oil saturation in a mechanistic numerical reservoir simulator. The simulation model was used to match the oil recovery and pressure drop of both secondary and tertiary polymer flood experiments. The results showed a strong correlation between the remaining oil saturation and the Deborah number.
- Asia (1.00)
- North America > United States > Texas (0.48)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Polymer Flooding of a Heavy Oil Reservoir with an Active Aquifer
Li, Zhitao (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Lotfollahi, Mohammad (The University of Texas at Austin) | Koh, Heesong (The University of Texas at Austin) | Luo, Haishan (The University of Texas at Austin) | Chang, Harry L. (Chemor Tech International) | Zhang, Jieyuan (Chemor Tech International) | Dempsey, Peter (Xcite Energy Resources Limited) | Lucas-Clements, Charles (Xcite Energy Resources Limited) | Brennan, Barny (Xcite Energy Resources Limited)
Abstract In recent years, polymer flooding of heavy oil has been extensively studied in laboratories and successfully applied in several fields. This paper reports the laboratory corefloods, development of mechanistic models, and simulation studies of polymer flooding in a heavy oil reservoir with active aquifer influxes. Bentley Field, operated by Xcite Energy Resources, is located on the UK Continental Shelf. Flow tests confirmed the existence of a large, active bottom aquifer which may cause polymer loss and decrease the economic attractiveness of polymer flooding. To analyze the impact of the aquifer on oil recovery efficiency, a reservoir simulation model was set up. Several development scenarios have been simulated for the optimization of development strategy. Conventional thinking, based on previously accepted EOR screening criteria, would be that the oil viscosity (approximately 1500 cp) exceeds the economic and technical limit of oil viscosity for polymer flooding. However, this paper demonstrates that the limit for effective polymer flooding can be extended to considerably higher viscosity oils. To validate the applicability of polymer flooding, two laboratory experiments were conducted with two different high permeability sandpacks. Due to the unconsolidated nature of the Bentley formation no cores were available. Waterflooding was stopped when water cut reached 90% and up to that point, less than 25% of oil in place had been recovered. However, the remaining oil saturations after both tertiary polymer corefloods achieved around a 5% level. We investigated the recovery mechanisms and developed a mechanistic model to match the laboratory observations. Simulation results show that for this heavy oil field with an active aquifer, polymer flooding economics can be improved by optimizing well locations, number of horizontal wells, polymer injection time, etc. In history matching coreflood experiments, two oil saturation reduction mechanisms were considered: (1) viscous polymer solution reduces viscous fingering and channeling effects especially in the heavy oil displacement process and also reduces remaining oil saturation after waterflooding; (2) remaining oil can be mobilized by viscoelastic properties of synthetic polymer solutions. Both mechanisms were considered in the simulation study where a favorable match of oil recovery and pressure drop was obtained. In this paper, polymer flooding is shown as a viable technology in a heavy oil reservoir, despite the highly unfavorable mobility ratio and strong aquifer influxes. Considering the diminishing conventional oil reserves, polymer flooding provides a non-thermal approach for producing heavy oil reserves that may be particularly attractive in an offshore environment, compared to thermal techniques.
- Asia (1.00)
- North America > United States > Texas (0.94)
- North America > Canada > Alberta (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- North America > United States > Michigan > Michigan Basin > Bentley Field > Dundee Limestone Formation (0.99)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.99)
- North America > Canada > Alberta > Bentley Field > Anadarko 11C St. Paul 11-15-58-7 Well (0.98)
Use of Co-Solvents to Improve Alkaline-Polymer Flooding
Fortenberry, Robert P. (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Nizamidin, Nabijan (The University of Texas at Austin) | Stephanie, S. Adkins (The University of Texas at Austin) | Pinnawala Arachchilage, Gayani W. (The University of Texas at Austin) | Koh, Heesong (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract We have found that the addition of low concentrations of certain inexpensive light co-solvents to alkaline-polymer solutions dramatically improves the performance of alkaline-polymer (AP) corefloods in two important ways. Firstly, addition of co-solvent promotes the formation of low viscosity microemulsions rather than viscous macroemulsions. Secondly, these light co-solvents greatly improve the phase behavior in a way that can be tailored to a particular oil, temperature and salinity. This new chemical EOR technology uses polymer for mobility control and has been termed Alkali-Co-solvent-Polymer (ACP) flooding. ACP corefloods perform as well as ASP corefloods while being simpler and more robust. We report 12 successful ACP corefloods using four different crude oils ranging from 12 to 24 °API. The ACP process shows special promise for heavy oils, which tend to have large fractions of soap-forming acidic components, but is applicable across a wide range of oil gravity.
- North America > United States > Texas (0.28)
- North America > United States > Nebraska (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.50)
- Geology > Mineral (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Nebraska > Singleton Field (0.99)
- North America > United States > Nebraska > Harrisburg Field (0.99)
- North America > United States > California > Whittier Field (0.99)
Rheology and Transport of Improved EOR Polymers under Harsh Reservoir Conditions
Kulawardana, Erandimala U. (The University of Texas at Austin) | Koh, Heesong (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Liyanage, Pathma J. (The University of Texas at Austin) | Upamali, Karasinghe A. (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract New polymers that are stable in harsh environments (high salinity/hardness and high temperature) are in high demand because of the need for chemical EOR in oil reservoirs with these conditions. Commonly used partially hydrolyzed polyacrylamides (HPAM) have been successfully used in the field for decades, but they hydrolyze at high temperature and eventually precipitate in the presence of high concentrations of divalent cations. This paper mainly focuses on rheology and transport behavior of scleroglucan (non-ionic polysaccharide) and N-vinylpyrrolidone (NVP)-polyacrylamide (AM) co-polymer. The rigid, rod-like, triple helical structure of scleroglucan imparts exceptional stability and its non-ionic functionality makes it insensitivity to salinity and hardness. By a different mechanism, NVP in modified HPAM protects the polymer's amide group against thermal hydrolysis, i.e., by sterically hindering the amide group. This allows maintaining high viscosity even in high salinity brines at high temperature. Both scleroglucan and NVP co- or ter-polymers show good filterability and transport properties in sandstone and carbonate cores at high temperature and in brine with high salinity and hardness. Therefore, both polymers are promising candidates for polymer flooding, surfactant-polymer flooding and alkali-surfactant-polymer flooding in hard brine at high temperature, but must be evaluated under specific reservoir conditions.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock (0.36)