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Collaborating Authors
SNF Holding Company
Low-Salinity Polymer Flood for Enhanced Oil Recovery in Low-Permeability Carbonates
Song, Haofeng (The University of Texas at Austin) | Ghosh, Pinaki (SNF Holding Company) | Bowers, Annalise (SNF Holding Company) | Niu, Fangya (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin (Corresponding author))
SNF Holding Company Summary Low-salinity waterflooding and brine ion modification, in general, can improve displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency (without significant viscoelasticity) but enhances sweep efficiency. The main objective of this work is to study the synergy between ion modification and polymer flooding for low-permeability carbonate rocks. High-salinity high-temperature reservoirs often need a sulfonated polymer for thermal stability in the high-salinity brine, but a low-salinity water (LSW) injection at that temperature can use a common hydrolyzed polyacrylamide (HPAM) polymer. The second objective of this study is to compare the performance of these two polymer injections. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of approximately 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10-20 md. A low-salinity polymer (LSP) flood was carried out using HPAM prepared in diluted seawater (with added sulfate concentrations). High-salinity polymer (HSP) floods increased the oil recovery in tight cores by 4-5% original oil in place (OOIP) due to higher pressure gradient. Low-salinity corefloods (with added sulfate ions) produced little incremental oil in a few pore volumes (PVs) of injection, but the combination of sulfated low-salinity brine and polymer improved the oil recovery by 8-10% OOIP in less than 1.5 PV. It is shown for the first time that the low-salinity brine with additional sulfate and negatively charged HPAM polymer changed the wettability of the originally oil-wet carbonate rock to water-wet. The synergy between polymer and wettability alteration can recover oil from bypassed pores and shorten the time for oil recovery. Introduction The application of partially HPAM) is usually limited to temperatures below 70 C when the injection brine contains high hardness. Acrylamide tertiary-butyl sulfonic acid (ATBS)- incorporated polyacrylamide improves thermal stability and is generally recommended for application in a high-temperature, high-salinity environment; however, it is more expensive than HPAM, and thus, its application is limited in oil fields.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral > Sulfate (0.91)
Reinjection of Produced (Sheared) Polymer in a Canadian Viscous Oil Reservoir: Considerations to Improve Economics and Reduce Carbon Footprint
Ghosh, Pinaki (SNF Holding Company (Corresponding author)) | 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) | Ould Metidji, Mahmoud (SNF SA) | Dupuis, Guillaume (SNF SA) | Ravikiran, Ravi (SNF Holding Company)
Summary Chemical enhanced oil recovery (EOR) 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 makes this technology very expensive and challenging to implement in the field. In the majority of cases, polymer flooding alone has proved to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, a challenging economic environment has operators looking for added economic and sustainable savings. The possibility of reinjection of produced (sheared) 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 (PW) 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 the presence of produced fluid containing residual polymer. The initial fluid-fluid testing and laboratory 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. Based on field observations and laboratory measurements, a 10 to 15% reduction in fresh polymer loading could be achieved through the reutilization of water containing residual polymer in these specific field conditions. Note, this case study involved produced polymer that was degraded through progressive cavity pumps (PCPs) resulting in only 15 to 20% of the injected viscosity in the produced fluids in addition to thermal and chemical degradations. The monophasic injectivity experiments in both outcrop cores resulted in similar resistance factors (RFs) for fresh polymer and blends with produced water reinjection containing residual polymer (PWcRP) solution, establishing the robustness of this blending system. Oil recovery experiments also resulted in similar oil displacement behavior [approximately 30 to 40% oil originally in place (OOIP) after 0.5 pore volumes (PV) waterflood] for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10 to 15% polymer loading reduction.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)
Summary The efficiency of a polymer flood depends on polymer transport and retention. Most studies on polymer transport in the literature have been focused on high-permeability sandstones. A limited number of investigations have been conducted in carbonates with permeability less than 100 md and very few in the presence of residual oil. In this work, transport of four polymers with different molecular weights (MW) and functional groups was studied in 1-ft-long Edwards Yellow outcrop cores (permeability < 50 md) with and without residual oil. The retention of polymers was estimated by both the material balance method and the double-bank method. The polymer concentration in coreflood effluents was measured by both the total organic carbon (TOC) analyzer and the capillary tube pressure drop. The results demonstrated that in tight carbonate rocks at 100% water saturation, partially hydrolyzed acrylamide (HPAM) polymers exhibited high retention (>160 µg/g), inaccessible pore volume (IPV) greater than 7%, and high residual resistance factor (RRF) (>9). The propagation of HPAM improved with the residual oil saturation and the retention was reduced by 50 µg/g because of thin oil films in pores that prevented the direct adsorption of the carboxyl group of polymers on the mineral surface. The sulfonated polyacrylamide, AN132, showed low retention (<15 µg/g) and negligible IPV in all experiments. The RRF of AN132 in the water-saturated rock was less than 2, indicating minimal blocking of pore throats in these tight rocks. The RRF of the AN132 polymer increased slightly in the presence of residual oil saturation because of partial blocking of the smaller pore throats available for polymer propagation in the oil-aged core.
- North America > United States > Texas (0.95)
- Asia > Middle East (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
A Critical Survey of the Rheological Properties Used to Predict Friction Reducer Performance
Aften, Carl W (SNF Holding Company) | Asgari, Yaser (SNF Holding Company) | Warren, Sharon (SNF Holding Company)
Abstract Increased interest in correlating rheological properties to the prediction of proppant transport and/or friction reduction performance produces sporadic and isolated experimental evidence. Obtaining accurate results specifically for viscosity, proposedly representative of proppant transport and friction reduction, is challenging and therefore, extrapolating polymer melt rheology to dilute polymer solutions is problematic particularly when applying linear viscoelastic theory. This paper presents a simultaneous, multivariable research approach illustrating how viscoelastic results and hypotheses for anionic, cationic, and amphoteric friction reducers in various brines provide insight into the limitations of constricted variable and experimental range methodology. Establishing a relevant application window for viscoelastic friction reducers is complicated. Guar gum linear gels are viscous in nature and more approachable than synthetic friction reducers when manipulated for rheological experimentation and field application extrapolation. However, crosslinking of guar gum linear gels results in a viscoelastic fluid of greater complexity, thus even the simplest of linear gels must be subjected to a variety of unique bench tests differentiated by and specific to individual service companies’ field application requirements. Friction reducers’ crossover of storage and loss moduli are dependent upon how the reducers were dispersed and hydrated with respect to brine characters, times, and mixing energies. Furthermore, correlating rheological measurements developed for the melt state may not appropriately adapt to the friction reducer application's dilute polymer state. Response surfaces were generated for various anionic, cationic, and amphoteric friction reducers with testing variables including brine type, loading, mixing rpm, mixing duration, shear rate, linear shear strain, responses of viscosity, and moduli with corresponding cross over results. Excellent regression was obtained from these complex, interactive response surfaces, revealing the breadth of variability obtained from complex experimentation and validating that studies using simplistic procedures provide limited and potentially biased performance conclusions. When relating rheology to friction reduction and proppant transport, whether in the lab or the field, and understanding the complexities of polymer absolute dispersion, dissolution, and kinetics indicate that, with respect to performance prediction, limited knowledge is gained from simple polymer make down regimens. This work offers a guideline for assimilating comprehensive studies of complex versus oversimplified, limited scope rheological measurement research and analyses.
Polymer Augmented Low Salinity Flooding in Low Permeability Carbonate Reservoirs
Haofeng, Song (The University of Texas at Austin) | Pinaki, Ghosh (SNF Holding Company) | Annalise, Bowers (SNF Holding Company) | Kishore, Mohanty (The University of Texas at Austin)
Abstract Low salinity waterflooding improves displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency, but enhances sweep efficiency. In this work, the synergy between low salinity and polymer flooding is studied for low permeability carbonate rocks. Polymer solutions were consecutively filtered through a 1.2 µm mixed cellulose ester membrane and a 0.4 µm polycarbonate membrane. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10-20 mD. Low salinity polymer flood was carried out using HPAM prepared in diluted seawaters (with modified sulfate concentrations). After extensive water floods, HPAM prepared in the 10 times-diluted seawater produced the same incremental oil recovery (4-5% original oil in place) as the ATBS-polymer AN132 prepared in the seawater. Increasing the sulfate concentration by four- and eight-folds doubled the incremental oil from low salinity polymer floods.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.69)
Reinjection of Produced (Sheared) Polymer in a Canadian Viscous Oil Reservoir: Considerations to Improve Economics and Reduce Carbon Footprint
Ghosh, Pinaki (SNF Holding Company (Corresponding author)) | 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) | Ould Metidji, Mahmoud (SNF SA) | Dupuis, Guillaume (SNF SA) | Ravikiran, Ravi (SNF Holding Company)
Summary Chemical enhanced oil recovery (EOR) 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 makes this technology very expensive and challenging to implement in the field. In the majority of cases, polymer flooding alone has proved to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, a challenging economic environment has operators looking for added economic and sustainable savings. The possibility of reinjection of produced (sheared) 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 (PW) 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 the presence of produced fluid containing residual polymer. The initial fluid-fluid testing and laboratory 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. Based on field observations and laboratory measurements, a 10 to 15% reduction in fresh polymer loading could be achieved through the reutilization of water containing residual polymer in these specific field conditions. Note, this case study involved produced polymer that was degraded through progressive cavity pumps (PCPs) resulting in only 15 to 20% of the injected viscosity in the produced fluids in addition to thermal and chemical degradations. The monophasic injectivity experiments in both outcrop cores resulted in similar resistance factors (RFs) for fresh polymer and blends with produced water reinjection containing residual polymer (PWcRP) solution, establishing the robustness of this blending system. Oil recovery experiments also resulted in similar oil displacement behavior [approximately 30 to 40% oil originally in place (OOIP) after 0.5 pore volumes (PV) waterflood] for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10 to 15% polymer loading reduction.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 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)
Critical Examination of Variables Effecting Friction Loop Results for Friction Reducer Selection
Aften, Carl (SNF Holding Company) | Asgari, Yaser (SNF Holding Company) | Bailey, Lee (SNF Holding Company) | Middleton, Gene (SNF Holding Company) | Muhammed, Farag (SNF Holding Company) | Pageni, Parasmani (SNF Holding Company) | Sullivan, Keith (SNF Holding Company)
Abstract Friction reducer evaluations for field application selection are conducted in laboratory benchtop recirculating flow loops or once-through systems. Industry standard procedures and benchtop flow loop (loop) system specifications for friction reduction assessment are nonexistent, though standardization efforts are recently documented. Research and papers correlating friction reducer performance to brine and additives have been published, however other key variables can significantly affect performance and therefore must be addressed to maximize product recommendation accuracy. This paper illustrates how variances affect results. Benchtop recirculating loops used for testing friction reduction products for a specific field's application vary significantly in system components, configurations, and test analyses. Crucial loop system variance examples include differing pipe diameters, pump configurations, flow meter types and placement, differential pressure section and full run lengths, reservoir designs, mixing conditions, and end performance calculations. Oil and gas producers and service companies are trending towards outsourcing friction reducers to independent testing laboratories for loop assessment results prior to recommending friction reducers for end use field applications. These recommendations may have inherent selection bias depending upon the loop system's components and configuration. Friction reduction calculations during loop testing do not consistently consider changes in viscosity and temperature, thereby altering absolute results when evaluating performance. To apply the simplified assumptions in standard pressure, drop methodology, equivalency in flow rate, density, viscosity, and temperature within the run must be maintained. Performance of the friction reducer in a specific brine and additive test run should primarily be dependent upon dosage and method of injecting friction reducer into the loop, however other variables can contribute to performance results. We presume equivalency in pipe roughness and proper loop cleansing. The effects of these variables on friction reduction response applying wide-ranging factors of flowrate, density, viscosity, and temperature are evaluated using designed experiments with responses plotted and illustrated in Cartesian and contour graphs. The result of these designed experiments identified that certain variables are more influential on friction reducers’ measured performances in standard loop experiments and require observation and documentation during performance testing. The final study in this work generated vastly different performance curves when all of the aspects of loop design, entry and differential run lengths, flow rate, injection method, friction reducer types and loadings, and brine types, densities, viscosities, and temperatures were held constant. The goal of benchtop loop testing is scaling for actual field applications. Scaling discrepancies persist however due to differing pipe diameters, fluid circuit designs, and pump types and rates combined with changing brine compositions, proppant, and chemical additive effects on friction reducer products. Understanding that different benchtop loops, or potentially the same benchtop loop, will generate differing results is intriguing, yet unsettling.
- North America > United States > Texas (0.29)
- North America > United States > West Virginia (0.28)
Abstract Polymer transport and retention affect oil recovery and economic feasibility of EOR processes. Most studies on polymer transport have focused on sandstones with permeabilities (k) higher than 200 mD. A limited number of studies were conducted in carbonates with k less than 100 mD and very few in the presence of residual oil. In this work, transport of four polymers with different molecular weights (MW) and functional groups are studied in Edwards Yellow outcrop cores (k<50 mD) with and without residual oil saturation (Sor). The retention of polymers was estimated by both the material balance method and the double-bank method. The polymer concentration was measured by both the total organic carbon (TOC) analyzer and the capillary tube rheology. Partially hydrolyzed acrylamide (HPAM) polymers exhibited high retention (> 150 μg/g), inaccessible pore volume (IPV) greater than 7%, and high residual resistance factor (>9). A sulfonated polyacrylamide (AN132), showed low retentions (< 20 μg/g) and low IPV. The residual resistance factor (RRF) of AN132 in the water-saturated rock was less than 2, indicating little blocking of pore throats in these tight rocks. The retention and RRF of the AN132 polymer increased in the presence of residual oil saturation due to partial blocking of the smaller pore throats available for polymer propagation in an oil-wet core.
- Asia > Middle East (0.94)
- North America > United States > Texas (0.47)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.49)