A Novel Sampling and Testing Procedure to Confirm Polymerflood Viscosity Retention at the Captain Field
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The Ithaca-operated Captain field is located in Block 13/22a in the U.K. sector of the North Sea, 130 km northeast of Aberdeen, in a water depth of 360 ft. The Captain Field has an adverse mobility ratio across all the producing reservoirs and so has undergone improved oil recovery by polymer flooding since 2011 using Anionic polyacrylamide (HPAM) in liquid form. This paper presents recent offshore wellhead sampling from the Captain facility that confirms high polymer solution viscosity retention from a producing well, even after significant mechanical degradation through the Electrical Submersible Pumps (ESP), which is used for artificial lift. The continuing commercial success of the Captain Field polymer flood is underpinned by maintaining polymer viscosity throughout the system. High polymer returns, combined with declining oil rates, may result in the continued operation of these wells to be unattractive. This paper summarises the data used to shut-in mature wells that are producing polymer to the surface, to enable the polymer flood to continue displacing oil to offset production wells. Samples were collected from the wellhead in oxygen free conditions into pressurized cylinders. The measurements in laboratory were taken inside a glove box to avoid oxygen ingress. The absence of oxygen was confirmed through measurements of dissolved oxygen and redox potential. Viscosity of the solutions have been measured with Brookfield viscometer inside the glove box and the results were compared to the expected viscosity from fresh non-degraded polymer solution. The expected viscosity was determined using a concentration – viscosity curve of a fresh polymer in synthetic Captain brine. Polymer solution concentration is measured on-site using KemConnect™ EOR, a time resolved fluorescence method, the collected samples were subsequently confirmed with size exclusion chromatography (SEC) in the laboratory. The polymer concentrations measured from these wellhead samples with KemConnect™ EOR were in the region of 700-900 ppm. Previously collected downhole viscosity samples confirmed >70% viscosity retention prior to being produced through the ESP, while 50-80% of the original viscosity was found to be retained after production through the ESP to the surface facilities under anaerobic conditions for the range of concentrations sampled. These findings demonstrate the resilience of the polymer product to degradation in a real-world operational setting. It also provides data that may be used to estimate the expected downhole polymer solution viscosity from wellhead samples for defined operating conditions. The ability to estimate polymer solution downhole viscosity retention from wellhead samples provides a simpler and less expensive method of estimating viscosity retention than downhole sampling, which is especially useful for wells that do not have downhole access for sample collection.
The Ithaca-operated Captain field is located in Block 13/22a in the U.K. sector of the North Sea, 130 km northeast of Aberdeen, in a water depth of 360 ft. The Captain Field has an adverse mobility ratio across all the producing reservoirs and so has undergone improved oil recovery by polymer flooding since 2011 using Anionic polyacrylamide (HPAM) in liquid form. This paper presents recent offshore wellhead sampling from the Captain facility that confirms high polymer solution viscosity retention from a producing well, even after significant mechanical degradation through the Electrical Submersible Pumps (ESP), which is used for artificial lift. The continuing commercial success of the Captain Field polymer flood is underpinned by maintaining polymer viscosity throughout the system. High polymer returns, combined with declining oil rates, may result in the continued operation of these wells to be unattractive. This paper summarises the data used to shut-in mature wells that are producing polymer to the surface, to enable the polymer flood to continue displacing oil to offset production wells. Samples were collected from the wellhead in oxygen free conditions into pressurized cylinders. The measurements in laboratory were taken inside a glove box to avoid oxygen ingress. The absence of oxygen was confirmed through measurements of dissolved oxygen and redox potential. Viscosity of the solutions have been measured with Brookfield viscometer inside the glove box and the results were compared to the expected viscosity from fresh non-degraded polymer solution. The expected viscosity was determined using a concentration – viscosity curve of a fresh polymer in synthetic Captain brine. Polymer solution concentration is measured on-site using KemConnect™ EOR, a time resolved fluorescence method, the collected samples were subsequently confirmed with size exclusion chromatography (SEC) in the laboratory. The polymer concentrations measured from these wellhead samples with KemConnect™ EOR were in the region of 700-900 ppm. Previously collected downhole viscosity samples confirmed >70% viscosity retention prior to being produced through the ESP, while 50-80% of the original viscosity was found to be retained after production through the ESP to the surface facilities under anaerobic conditions for the range of concentrations sampled. These findings demonstrate the resilience of the polymer product to degradation in a real-world operational setting. It also provides data that may be used to estimate the expected downhole polymer solution viscosity from wellhead samples for defined operating conditions. The ability to estimate polymer solution downhole viscosity retention from wellhead samples provides a simpler and less expensive method of estimating viscosity retention than downhole sampling, which is especially useful for wells that do not have downhole access for sample collection.
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.
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.
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