Summary Alkali polymer (AP) flooding is a promising enhanced oil recovery (EOR) method to increase oil recovery from reactive oils. It is essential to carefully select the alkali and polymer type and concentration to optimize incremental oil recovery. In addition to the conventional laboratory tests for polymer flooding, the effects of the high pH on the polymer and its evolving properties over time need to be investigated. Consideration of near-wellbore and reservoir effects is key in designing the process. We are showing how understanding and taking advantage of the polymer performance in a high pH environment allow for cost reduction and increase in injectivity and incremental oil recovery for AP projects. The polymer performance was evaluated for AP flooding of the Matzen field (Austria). Evaluations included changes in polymer rheology during aging at high pH conditions, phase behavior tests, and single-/two-phase corefloods with aged and nonaged polymer solutions. In addition, adsorption of the aged polymer and interfacial tension (IFT) were measured. The aging was studied in anaerobic conditions at reservoir temperature and through an accelerated method at elevated temperatures. The accelerated method developed earlier for neutral pH range provides a possibility to run aging at elevated temperatures in a short time frame and transfer the data to reservoir temperature to give information on the long-term performance. The transfer takes place through a conversion factor derived from the first-order kinetics of acrylamide hydrolysis in pH 6–8. In the present work, the applicability of the accelerated method is evaluated for elevated pH by determining the degree of polymer hydrolysis over time via nuclear magnetic resonance and linking it to viscosity performance at various temperatures. The AP conditions in the Matzen AP flooding project (pH > 10) lead to an increased initial rate of polymer hydrolysis of the tested hydrolyzed polyacrylamide (HPAM) by a factor of 100 compared to hydrolysis at a neutral pH level. This resulted in a rapid increase in a polymer solution viscosity of 160% compared with initial conditions within days at a reservoir temperature of 49°C, after which the viscosity leveled off. Accelerated aging experiments at higher temperatures predict long-term stability of the increased viscosity level for several years. Single-phase injection test in a representative core confirmed the performance of the aged solution compared to a nonaged solution at the same polymer concentration. The retention of polymers is reduced in AP conditions compared with traditional neutral pH conditions, 19 vs. 48 µg/g in the static adsorption test, respectively. Two-phase coreflood tests showed increased polymer viscosity at reservoir conditions. The displacement efficiency of the aged and nonaged polymer solution was similar, confirming the potential for cost savings using lower polymer concentration. This is leading to an improved injectivity and makes use of the increased polymer viscosity down in the reservoir through hydrolysis. The current work combines multiple aspects that should be considered in the proper planning of AP projects—not only improvements in polymer viscosity performance due to water softening but also long-term effects due to increased pH. Additionally, these aspects are combined with changes in adsorption properties. The results show that the design of AP projects will benefit from the holistic approach and understanding the changes in polymer rheology with time. The costs of AP projects can be reduced owing to the lower required polymer concentrations for the same displacement efficiency and reduced retention of polymer. An efficient design of AP projects takes good injectivity of nonaged polymers and the aging of the polymer solutions in alkali into account. Overall, we aim to reduce the polymer concentration—which is a key cost driver—compared with a nonaged application. We show that for AP effects, these effects should be evaluated to improve the economics.
Alkali Polymer (AP) flooding is a promising Enhanced Oil Recovery (EOR) method to increase oil recovery from reactive oils. It is essential to carefully select the alkali and polymer type and concentration to optimize incremental oil recovery. In addition to the conventional laboratory tests for polymer flooding, the effects of the high pH on the polymer and its evolving properties over time need to be investigated. Consideration of near-wellbore and reservoir effects is a key in designing the process. We are showing how understanding and taking advantage of the polymer performance in a high pH environment allows to reduce costs, increase injectivity and incremental oil recovery for AP projects. The polymer performance was evaluated for AP flooding of the Matzen field (Austria). Evaluations included changes in polymer rheology during aging at high pH conditions, phase behavior tests, and single/two-phase core floods with aged and non-aged polymer solutions. In addition, adsorption of the aged polymer and interfacial tension was measured. The aging was studied in anaerobic conditions at reservoir temperature and through an accelerated method at elevated temperature. The degree of polymer hydrolysis over time was determined via NMR and linked to viscosity performance. The AP conditions in the Matzen AP flooding project (pH > 10) lead to an increased initial rate of polymer hydrolysis of the tested HPAM by a factor of 100 compared to hydrolysis at a neutral pH level. This resulted in a rapid increase in polymer solution viscosity of 160 % compared with initial conditions within days at reservoir temperature of 49 °C, after which the increase leveled off. Accelerated aging experiments at higher temperature predict long-term stability of the increased viscosity level for several years. Single-phase injection test in representative core confirmed the performance of the aged solution compared to a non-aged solution at the same polymer concentration. The retention of polymers is reduced in AP conditions compared with traditional neutral pH conditions. Two-phase core flood tests showed the increased polymer viscosity at reservoir conditions. The displacement efficiency of the aged and non-aged polymer solution was similar confirming the potential for cost savings using lower polymer concentration and making use of the increased polymer viscosity owing to hydrolysis. The results show that the design of alkali polymer projects needs to take the changing polymer rheology with time into account. The costs of alkali polymer projects can be reduced owing to the lower required polymer concentrations for the same displacement efficiency and reduced retention of polymer. An efficient design of alkali polymer projects takes good injectivity of non-aged polymers and the aging of the polymer solutions in alkali into account.
In this work, we present various evaluations that are key prior field applications. The workflow combines laboratory approaches to optimize the usage of polymers in combination with alkali to improve project economics. We show that the performance of AP floods can be optimized by making use of lower polymer viscosities during injection but increasing polymer viscosities in the reservoir owing to “aging” of the polymers at high pH. Furthermore, AP conditions enable the reduction of polymer retention in the reservoir, decreasing the utility factors (kg polymers injected/incremental bbl. produced). We used aged polymer solutions to mimic the conditions deep in the reservoir and compared the displacement efficiencies and the polymer adsorption of non-aged and aged polymer solutions. The aging experiments showed that polymer hydrolysis increases at high pH, leading to 60% higher viscosity in AP conditions. Micromodel experiments in two-layer chips depicted insights into the displacement, with reproducible recoveries of 80% in the high-permeability zone and 15% in the low-permeability zone. The adsorption for real rock using 8 TH RSB brine was measured to be approximately half of that in the case of Berea: 27 µg/g vs. 48 µg/g, respectively. The IFT values obtained for the AP lead to very low values, reaching 0.006 mN/m, while for the alkali, they reach only 0.44 mN/m. The two-phase experiments confirmed that lower-concentration polymer solutions aged in alkali show the same displacement efficiency as non-aged polymers with higher concentrations. Reducing the polymer concentration leads to a decrease in EqUF by 40%. If alkali–polymer is injected immediately without a prior polymer slug, then the economics are improved by 37% compared with the polymer case. Hence, significant cost savings can be realized capitalizing on the fast aging in the reservoir. Due to the low polymer retention in AP floods, fewer polymers are consumed than in conventional polymer floods, significantly decreasing the utility factor.
Summary Horizontal wells are frequently used to increase injectivity and for cost-efficient production of mobilized oil in polymer-augmented waterfloods. Usually, only fluid and polymer production data at the wellhead of the production well are available. We used inflow tracer technology to determine changes in hydrocarbon influx owing to polymer injection and to determine the connection from various zones of the horizontal injector to the horizontal producer. Inflow tracer technology was introduced in horizontal polymer injection and production wells. In the production wells, tracers are released when they are contacted by water and oil. Oil and water tracer systems were used in the horizontal production wells. The changes in the observed tracer concentration were used to quantify changes in influx from various sections of the horizontal producers owing to polymer injection. The inflow tracer technology applied in the horizontal injection wells demonstrates connectivity between different sections of the injection wells and two surrounding vertical and horizontal production wells and opens the usage of this technology for interwell water tracer applications. Inflow tracer technology enables one to elucidate the inflow from various sections of the horizontal wells and the changes thereof, even quantifying changes in influx of various fluids (oil and water). The information shows which sections are contributing and the substantial changes in the influx of oil from the various zones due to polymer solution injection. The overall incremental oil could be allocated to the various horizontal well sections based on the tracer results. Even zones that almost exclusively produced water before polymer injection showed a significant increase in oil influx. The inflow tracer technology installed in the injection well allowed us to analyze the connectivity of the injector to producer not only globally but spatially along the horizontal well. These data are used for reservoir characterization, to condition numerical models, and for reservoir management. Conventional interwell tracer technology allows one to determine the connectivity and connected volumes of horizontal well polymer field developments. However, it reveals neither information about influx of the sections nor the connectivity of various sections of the horizontal wells. Inflow tracer technology closes this gap; it allows one to quantify changes in influx of the fluids. Furthermore, the newly developed installed injection well tracer technology gives spatial information about the connectivity of the horizontal well sections.
Alkali injection leads to in-situ soap generation of high TAN number oil and residual oil reduction accordingly. We are showing that the performance of AP floods can be optimized by making use of lower polymer viscosities during injection but increasing polymer viscosities in the reservoir owing to "aging" of the polymers at high pH. Furthermore, AP conditions enable reducing polymer retention in the reservoir decreasing the Utility Factors (kg polymers injected / incremental bbl. produced). Phase behavior tests were performed to understand the oil/alkali solution interaction and interfacial tension (IFT) was measured. Micromodel floods addressed displacement effects while two-phase core floods covered the displacement efficiency of alkali polymer solutions. We used aged polymer solutions to mimic the conditions deep in the reservoir and compared the displacement efficiencies and the polymer adsorption of non-aged and aged polymer solutions. IFT measurements showed that saponification (41 μmol_g saponifiable acids) at the oil-alkali solution interface is very effectively reducing the IFT. Alkali phase experiments confirmed that emulsions are formed initially and supported the potential for residual oil mobilization. Aging experiments revealed that the polymer hydrolysis rate is substantially increased at high pH compared to polymer hydrolysis at neutral pH resulting in 60 % viscosity increase in AP conditions. Within the reservoir, the fast aging of polymer solutions in high pH results in increase to target viscosity while maintaining low adsorption owing to alkali and softened water. Hence, injectivity of alkali polymer solutions can be improved over conventional polymer flooding. The two-phase experiments confirmed that lower concentration polymer solutions aged in alkali show the same displacement efficiency as non-aged polymers with higher concentrations. Hence, significant cost savings can be realized capitalizing on the fast aging in the reservoir. Due to the low polymer retention in AP floods, less polymers are consumed than in conventional polymer floods significantly decreasing the Utility Factor (injected polymers kg/incremental bbl. produced). Overall, the work shows that Alkali/Polymer (AP) injection leads to substantial incremental oil production of reactive oils. A workflow is presented to optimize AP projects including near-wellbore and reservoir effects. AP flood displacement efficiency must be evaluated incorporating aging of polymer solutions. Significant cost savings and increasing efficiency can be realized in AP floods by incorporating aging of polymers and taking the reduced polymer adsorption into account.
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