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Collaborating Authors
Tavassoli, Shayan
The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells
Ho, Jostine Fei (The University of Texas at Austin) | Tavassoli, Shayan (The University of Texas at Austin) | Patterson, James W. (The University of Texas at Austin) | Shafiei, Mohammadreza (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Bommer, Paul M. (The University of Texas at Austin) | Bryant, Steven L. (The University of Texas at Austin) | Balhoff, Matthew T. (The University of Texas at Austin)
Summary The potential leakage of hydrocarbon fluids or carbon dioxide (CO2) out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil-and-gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 µm can pose a significant leakage danger with effective permeability in the range of 0.1–1.0 md. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair; thus, a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application with pH-triggered polymeric sealants could potentially be the solution to plugging these fractures. The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. The pH-sensitive microgels viscosify after neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition with real-time visual observation and measurements of pressure gradient and effluent pH. Although the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cations from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that were subjected to various degrees of syneresis often failed to hold backpressures. Multiple chemicals were tested for pretreatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer-gel strength is determined by recording the maximum-holdback pressure gradients during liquid-breakthrough tests after various periods of pretreatment and polymer shut-in time. Cores pretreated with Na5P3O10 successfully held up to an average of 70 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2-storage applications. The use of such inexpensive, pH-triggered polyacrylic acid polymer allows the sealing of leakage pathways effectively under high-pH conditions.
Summary A systematic simulation study of gravity-stable surfactant flooding was performed to understand the conditions under which it is practical and to optimize its performance. Different optimization schemes were introduced to minimize the effects of geologic parameters and to improve the performance and the economics of surfactant floods. The simulations were carried out by use of horizontal wells in heterogeneous reservoirs. The results show that one can perform gravity-stable surfactant floods at a reasonable velocity and with very-high sweep efficiencies for reservoirs with high vertical permeability. These simulations were carried out with a 3D fine grid and a third-order finite-difference method to accurately model fingering. A sensitivity study was conducted to investigate the effects of heterogeneity and well spacing. The simulations were performed with realistic surfactant properties on the basis of laboratory experiments. The critical velocity for a stable surfactant flood is a function of the microemulsion (ME) viscosity, and it turns out there is an optimum value that one can use to significantly increase the velocity and still be stable. One can optimize the salinity gradient to gradually change the ME viscosity. Another alternative is to inject a low-concentration polymer drive following the surfactant slug (without polymer). Polymer complicates the process and adds to its cost without a significant benefit in most gravity-stable surfactant floods, but an exception is when the reservoir is highly layered. The effect of an aquifer on gravity-stable surfactant floods was also investigated, and strategies were developed for minimizing its effect on the process.
Low-Salinity Surfactant Flooding—A Multimechanistic Enhanced-Oil-Recovery Method
Tavassoli, Shayan (The University of Texas at Austin) | Korrani, Aboulghasem Kazemi (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Summary We have applied UTCHEM-IPhreeqc to investigate low-salinity (LS) waterflooding and LS surfactant (LSS) flooding. Numerical-simulation results were compared with laboratory experiments reported by Alagic and Skauge (2010). UTCHEM-IPhreeqc combines the UTCHEM numerical chemical-flooding simulator with IPhreeqc, the United States Geological Survey geochemical model. The IPhreeqc model was coupled to UTCHEM to model LS waterflooding as a function of geochemical reactions. The surfactant coreflood experiments were performed in vertical cores without using polymer or other mobility-control agents. These experiments were performed at a velocity greater than the critical velocity for a gravity-stable flood. After history matching the experiments, additional numerical simulations of surfactant floods at the critical velocity were run to estimate the performance under stable conditions. We also simulated a surfactant flood at higher salinity with lower interfacial tension (IFT) and compared the results with the LSS flood. These results provide new insights into LS waterflooding and surfactant flooding. Addition of surfactants prevents the retrapping of oil that was initially mobilized using LS-brine injection. The results show that the proper selection of surfactant and the design of the surfactant flood might surpass the potential benefits of LS waterflooding in terms of both higher oil recovery and lower cost. Specially, a more-effective method is expected in a stable design with no preflood.
- Geology > Geological Subdiscipline > Geochemistry (0.90)
- Geology > Mineral > Silicate (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells
Ho, Jostine Fei (The University of Texas at Austin) | Patterson, James W. (The University of Texas at Austin) | Tavassoli, Shayan (The University of Texas at Austin) | Shafiei, Mohammadreza (The University of Texas at Austin) | Balhoff, Matthew T. (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Bommer, Paul M. (The University of Texas at Austin) | Bryant, Steven L. (The University of Texas at Austin)
Abstract The potential leakage of hydrocarbon fluids or CO2 out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil and gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 microns can pose a significant leakage danger with effective permeability in the range of 0.1–1 mD. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair, thus a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application using pH-triggered polymeric sealants could potentially be the solution to plugging these fractures. The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. pH-sensitive microgels viscosify upon neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition via real-time visual observation and measurements of pressure gradient and effluent pH. While the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cation from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that subjected to various degrees of syneresis often failed to hold back pressures. Multiple chemicals were tested for pre-treatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer gel strength is determined by recording the maximum holdback pressure gradients during liquid breakthrough tests after various periods of pre-treatment and polymer shut-in time. Cores pre-treated with Na5P3O10 successfully held up to an average of 80 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2 storage applications. The use of such inexpensive, pH-triggered poly-acrylic acid polymer allows to seal leakage pathways effectively under high pH conditions.
Summary Recent surfactant-flooding experiments have shown that very-efficient oil recovery can be obtained without mobility control when the surfactant solution is injected at less than the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale on the basis of gravity-stable surfactant-flooding experiments at the laboratory scale. The scaleup process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated 3D heterogeneous reservoirs by use of a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravity-stable surfactant floods, and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be performed without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.
Abstract A systematic simulation study of gravity-stable surfactant floods has been done to understand the conditions under which it is practical and to optimize its performance. Different optimization schemes have been introduced to minimize the effects of geologic parameters and improve the performance and the economics of surfactant floods. The simulations were carried out using horizontal wells in heterogeneous reservoirs. The results show that gravity-stable surfactant floods can be done at a reasonable velocity and with very high sweep efficiencies for reservoirs with high vertical permeability. These simulations were carried out using a three-dimensional fine grid and a third-order finite-difference method to accurately model fingering. A sensitivity study was conducted to investigate the effects of heterogeneity and well spacing. The simulations were performed using realistic surfactant properties based on laboratory experiments. The critical velocity for a stable surfactant flood is a function of the microemulsion viscosity and it turns out there is an optimum value that can be used to significantly increase the velocity and still be stable. The salinity gradient can be optimized to gradually change the microemulsion viscosity. Another alternative is to inject a low concentration polymer drive following the surfactant slug (without polymer). Polymer complicates the process and adds to its cost without a significant benefit in most gravity-stable surfactant floods, but an exception is when the reservoir is highly layered. The effect of an aquifer on gravity-stable surfactant floods was also investigated and strategies were developed for minimizing its effect on the process.
Low Salinity Surfactant Flooding – A Multi-Mechanistic Enhanced Oil Recovery Method
Tavassoli, Shayan (The University of Texas at Austin) | Korrani, Aboulghasem Kazemi (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract We have applied UTCHEM-IPhreeqc to investigate low salinity waterflooding and low salinity surfactant flooding. Numerical simulation results have been compared with laboratory experiments reported by Alagic and Skauge (2010). UTCHEM-IPhreeqc combines the UTCHEM numerical chemical flooding simulator with IPhreeqc, the United States Geological Survey geochemical model. The IPhreeqc model was coupled to UTCHEM to model low salinity waterflooding as a function of geochemical reactions. The surfactant coreflood experiments were done in vertical cores without using polymer or other mobility control agents. These experiments were done at a velocity greater than the critical velocity for a gravity-stable flood. After history matching the experiments, additional numerical simulations of surfactant floods at the critical velocity were run to estimate the performance under stable conditions. We also simulated a surfactant flood at higher salinity with lower IFT and compared the results with the low salinity surfactant flood. These results provide new insights into low salinity waterflooding and surfactant flooding.
- Geology > Geological Subdiscipline > Geochemistry (0.91)
- Geology > Mineral > Silicate (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
Summary Classical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world's largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.
Abstract Recent surfactant flooding experiments have shown very efficient oil recovery can be obtained without mobility control when the surfactant solution is injected below the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale based on gravity-stable surfactant flooding experiments at the laboratory scale. The scale up process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated three-dimensional heterogeneous reservoirs using a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravity-stable surfactant floods and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be done without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.
Selection of Candidate Horizontal Wells and Determination of the Optimal Time of Refracturing in Barnett Shale (Johnson County)
Tavassoli, Shayan (University of Texas At Austin) | Yu, Wei (University of Texas At Austin) | Javadpour, Farzam (University of Texas At Austin) | Sepehrnoori, Kamy (University of Texas At Austin)
Abstract The observed uneconomic production performance in many shale gas horizontal wells suggests refracturing as a restimulation treatment to revive economic gas production. To achieve high-performance re-stimulation, it is critical to select the right well among many other wells in the area and determine the proper time of refracturing. Well selection is challenging in shale gas horizontal wells because of the complexity of natural and induced fracture networks and in many cases due to insufficient reservoir and completion data. Selection of the candidate well and the time of refracturing can be made based on a thorough numerical simulation study developed by precise modeling of hydraulic fractures and refracturing process. Accurate modeling can only be accomplished by considering formation of fracture networks. Induced fracture networks are formed by an altered stress-field as a consequence of the fracturing process and are evidenced by micro-seismic hydraulic fracture monitoring techniques. Tavassoli et al. (2013) modeled gas production of a refractured well in the Barnett formation and validated their simulation methodology with the available field data. The validated model was used to predict gas production after refracturing the well. They then performed systematic sensitivity analyses to specify the characteristics of shale gas horizontal well suitable for refracturing and defined well screening criteria and optimal time of refracturing. In this study we extended their original work to study 188 horizontal wells in Barnett (Johnson County) to identify wells with potentials for refracturing. We found that among these 188 wells only 11 wells are suitable for refracturing and the best time to perform hydraulic fracturing is between 3½ to 5½ years after initial production.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Ohio > Newark Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (4 more...)