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Collaborating Authors
Results
Polymer EOR Assessment Through Integrated Laboratory and Simulation Evaluation for an Offshore Middle East Carbonate Reservoir
Jabbar, MuhammadYousuf (ADNOC Offshore) | Xiao, Rong (ExxonMobil Production Company) | Teletzke, Gary F. (ExxonMobil Upstream Research Company) | Willingham, Thomas (ADNOC Offshore) | Al Obeidli, Amna (ADNOC Offshore) | Al Sowaidi, Alunood (ADNOC Offshore) | Britton, Chris (Ultimate EOR services) | Delshad, Mojdeh (Ultimate EOR services) | Li, Zhitao (Ultimate EOR services)
Abstract A laboratory study was performed to identify a robust chemical EOR solution for a complex low-permeability carbonate reservoir. The study consisted of two phases of work. The first phase included development of a surfactant-based EOR method (Jabbar et al., 2017). The results were promising, but the proposed surfactant design was economically challenged due to high surfactant adsorption. Initial screening recommended polymer to be considered for sweep improvement and conformance control although reservoir complexity and current field development presents a challenge. This paper is focused on the polymer EOR evaluation and discusses the extensive evaluation process that was followed. The laboratory study included polymer rheology, thermal stability, and transport tests with a novel pre-shearing method, live-condition core flood tests to evaluate dynamic polymer adsorption and description of key chemical and flow properties, and a history match of the core flood test results. In addition, preliminary simulation studies were performed, which demonstrated the recovery potential of polymer flooding. Two modified, low-molecular weight HPAM polymers were tested and have suitable viscosifying power in injected seawater (41 g/mL TDS) at 100ยฐC. The long-term thermal stability results showed that only the more salt-tolerant polymer is stable at 100ยฐC and retains >80% of initial viscosity at 300 days. The stable polymer was tested in a series of single-phase core floods to evaluate transport through low-permeability (5-10 mD) reservoir cores at 100ยฐC. A novel pre-shearing method was developed where pre-sheared polymer solution with 30% of its original viscosity (~3 cP) transported without significant plugging. Finally a high-pressure live-oil two-phase oil recovery coreflood in preserved reservoir core was performed. The incremental oil recovery with three PV's of polymer solution injection was approximately 17% OOIP. Pressure drop was 47 psi/ft., ~3-5 times higher than that of waterflood, for the 3 cP polymer solution. The polymer breakthrough times and resistance factor were reasonable with no evidence of plugging or injectivity issues considering permeability and viscosity of fluids. The polymer retention was measured to be 150 ยฑ 50 ฮผg/g rock, which is higher than a traditional HPAM flood in high-permeability sandstone rock. The laboratory results obtained thus far are promising considering very harsh and challenging reservoir conditions. The study also highlights an "up-scaleable" pre-shearing method for field application. In the simulation study, a sector model with representative geological features was taken from the full-field simulation model. Measured physical properties from the laboratory evaluation were used as input for the polymer flood simulation. Recovery uplift from polymer flood was found to be ~5% OOIP with significant reduction in water production and reasonable chemical utilization of <10 lbs. per incremental barrel. The simulation study demonstrated promising potential of polymer flooding for the targeted reservoir.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study > Negative Result (0.34)
Conditioning Polymer Solutions for Injection into Tight Reservoir Rocks
Driver, Jonathan W. (Ultimate EOR Services and University of Texas) | Britton, Chris (Ultimate EOR Services) | Hernandez, Richard (Ultimate EOR Services) | Glushko, Danylo (Ultimate EOR Services) | Pope, Gary A. (University of Texas) | Delshad, Mojdeh (Ultimate EOR Services)
Abstract Water soluble polymers have been used for decades as mobility control agents for tertiary recovery processes. Viscosity is conferred by the large hydrated size of the individual high molecular weight polymer molecules; their single-molecule hydrated size is so large that it can rival the diameters of the pore throats conducting the fluid, and it is widely understood that there are permeability limits below which solutions of such polymers cannot transport well. Delineating exactly where these limits are remains challenging, and operators are left to use whatever anecdotal evidence is available to decide whether to inject polymer, and, if so, what type and molecular weight to use. A rule of thumb is that when the permeability of a rock falls below 100 millidarcys, transport can be problematic. We have developed processing techniques for laboratory tests to condition polymer solutions for injection into reservoir carbonate cores with permeabilities below 10 millidarcys and median pore radii below one micron. Shearing and tight filtration were used to reduce the maximum size of polymers in solution while retaining as much viscosity as possible. Subsequent filtration was used to quantitatively assess the plugging behavior of the product solution across a range of pore sizes smaller than those which conduct in the rock sample. Coreflood injectivity tests revealed the onset of face plugging as a function of average polymer size. Co-solvent was shown to dramatically improve the transport of sulfonated polyacrylamides when face plugging did not occur, and those improvements were mirrored in benchtop filtration data. This improvement came despite equal-or-better viscosity in the polymer solution, demonstrating that the co-solvent did not reduce the polymer's hydrated size and therefore most likely weakens inter-molecular associations in solution. In sum, the data indicate that permeability loss occurred by two mechanisms: simple mechanical plugging and progressive adsorption, likely mediated by inter-molecular entanglements. These two permeability reduction mechanisms should be rectified by different means.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.70)
Mechanistic Simulation of Polymer Injectivity in Field Tests
Lotfollahi, Mohammad (University of Texas at Austin) | Farajzadeh, Rouhi (Shell Global Solutions International and Delft University of Technology) | Delshad, Mojdeh (University of Texas at Austin) | Al-Abri, Al-Khalil (Petroleum Development Oman) | Wassing, Bart M. (Petroleum Development Oman) | Al-Mjeni, Rifaat (Petroleum Development Oman) | Awan, Kamran (Petroleum Development Oman) | Bedrikovetsky, Pavel (University of Adelaide)
Summary Polymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates. The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times. One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.
- North America > United States > Texas (0.29)
- Asia > Middle East > Oman (0.28)
- Europe > Netherlands > South Holland (0.28)
- (2 more...)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)
Mechanistic Simulation of Polymer Injectivity in Field Tests
Lotfollahi, Mohammad (The University of Texas at Austin, Texas, US) | Farajzadeh, Rouhi (Shell Global Solutions International, Rijswijk, The Netherlands, Delft University of Technology, The Netherlands) | Delshad, Mojdeh (The University of Texas at Austin, Texas, US) | Al-Abri, Khalil (Petroleum Development Oman, Muscat, Oman) | Wassing, Bart M. (Petroleum Development Oman, Muscat, Oman) | Mjeni, Rifaat (Petroleum Development Oman, Muscat, Oman) | Awan, Kamran (Petroleum Development Oman, Muscat, Oman) | Bedrikovetsky, Pavel (University of Adelaide, Australia)
Abstract Polymer flooding is one of the most widely used chemical enhanced oil recovery methods due to its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution is often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior at near well-bore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, we propose a new model to history match field injection rate/pressure data. The pertinent equations for deep-bed filtration and external cake build-up in radial coordinate were coupled to the viscoelastic polymer rheology to capture important mechanisms. We selected radial coordinate in order to minimize the velocity/shear rate errors due to gridblock size in Cartesian coordinate. We used filtration theory and successfully history matched the field data. We performed systematic simulations and studied the impact of adsorption (retention), shear thickening, deep bed filtration, and external cake formation to explain the well injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure during early times is attributed to the shear thickening rheology at high velocities experienced by viscoelastic HPAM polymers around the wellbore and the permeability reduction due to polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external cake growth is responsible for the sharper increase in injection pressure at the later times. The proposed model can be used to calculate the injectivity of the polymer injection wells, understand the contribution of different phenomena on the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.
- Europe > Austria (0.69)
- North America > United States > Texas (0.69)
- Asia > Middle East > Oman (0.68)
- Europe > Netherlands > South Holland (0.46)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)