Polymer Flood Pilot Research Articles

EOR simulation of polymer flooding

Enhanced oil recovery (EOR) techniques, such as polymer flooding, have gained significant attention as a means to maximise hydrocarbon extraction from reservoirs. The success of polymer flooding is intricately tied to the complex interplay between fluid properties, reservoir heterogeneity, and injection strategies. It is admitted in classical modelling methodologies, to account for the mobility ratio in polymer flooding by scaling it with the help of the shear rate in situ. The accuracy of shear assessment therefore rules the mobility of oil and the global process efficiency. It is assumed to depend not solely on pore radius, rate, and porosity, but also on a dimensional parameter known as the shape factor, which varies according to the specifications of several authors. When lab measurement is available, it is possible to adjust this value to match the shear rate recorded from a rheometer at feeding stage, ahead of the core. In the present paper the consequence of not performing this stage in the case of a core flood, then in the simulation of a polymer flood pilot is investigated. An alteration of the recovery factor is then expected. The amplitude shall result from the coupling between pore-scale effects and reservoir-scale response, induced by geological constraints such as reservoir layers productivity, aquifer response, and multiphase dynamics. Relative effect and influence on reservoir parameters will be quantified, commented, and discussed.

Data driven approach using capacitance resistance model to determine polymer in-situ retention level

Polymer retention in reservoir rock can significantly impair polymer flood effectiveness and increases the required polymer bank slug size to maintain mobility control. Laboratory measurements such as static adsorption and coreflooding test are typically performed to assess polymer retention level in the reservoir, however such measurements are sensitive to rock sample used and its grain size, and the preparation method. Hence, to obtain the most representative data, polymer retention level measurement should be done at reservoir in-situ condition.This study presents an investigation to couple capacitance resistance model with polymer transport model. By utilizing produced polymer concentration data, polymer injection allocation can be determined. The coupled model also provides rapid polymer retention level estimate based on in-situ data. This model has been validated with numerical reservoir model and applied to evaluate a field polymer flood pilot.

Efforts Lead to Formulation of High-Performance ASP

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22729, “ASP Formulation Development Journey: Optimization, Validation, and Quality Control for Mangala Field,” by Nitish Koduru, Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn Oil and Gas. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Mangala is a large low-salinity, high-quality fluvial oil field in India with stock-tank oil initially in place (STOIIP) of more than 1 billion bbl of waxy and moderately viscous crude. Aqueous-based chemical enhanced oil recovery (EOR) has been identified as the most suitable technique to improve recovery over waterflooding. The objective of the complete paper is to describe alkaline/surfactant/polymer (ASP) formulation development for Mangala, which involved more than 30 corefloods at the time of writing, with formulation design changing over time. Field Background The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API in the oil column. The crude has in-situ viscosity of 9–17 cp. The crude has good napthenic acid content and reacts with alkali to produce in-situ soap. Immediately after the field’s appraisal stage, work to identify the most suitable EOR process began. First, a polymerflooding pilot was conducted during 2011–12. The encouraging results led to full-field polymerflooding implementation in November 2014. The ASP pilot performed well; incremental oil recovery over polymerflooding was estimated to be in the range of 20–25% of the pilot STOIIP. The initial development plan involved implementing a hot waterflooding production startup to maintain reservoir pressure and effective sweep. The Upper Fatehgarh FM1 and FM2 units were developed with inverted nine-spot patterns, while the more-homogeneous lower Fatehgarh (FM3 and FM4) were developed with downdip injectors and updip horizontal producers. The Mangala field began producing under a hot waterflood in 2009, with the injected water heated to approximately 80–85°C to avoid wax deposition. Injection was started within a few months of first production. At the time of writing, the field is under polymerflooding, with results largely in line with expectations. The field, which has already produced approximately 37% of the STOIIP, is on a declining production trend, and large-scale ASP flooding is being considered as the next development initiative to arrest production decline and increase overall recovery. The complete paper discusses EOR screening studies; ASP formulations, including the initial formulation; the method adopted for selection of chemical suppliers for the pilot test; optimization of ASP formulations tested in the pilot; validation of the developed formulation to other layers of the field; and planned quality-control processes to be used during procurement of chemicals for larger applications of ASP floods in the field. This synopsis concentrates on the last three of these factors, rather than the formulations considered, which, in addition to the initial formulation, included the following: - Formula 2: ASP formulation with a sacrificial surfactant - Formula 3: ASP formulation with a single surfactant - Formula 4: Formulation with a highly hydrophilic, large-hydrophobe surfactant

Technology Focus: History Matching and Forecasting (April 2023)

_ This year’s history matching and forecasting selections cover topics that include performance prediction of a polymerflood pilot in a heavy oil reservoir, multivariate characterization and modeling of a paleo zone, and multiwell pressure history matching in an unconventional reservoir. The authors of paper SPE 206247 developed a history-matched reservoir simulation model for a polymerflood pilot to enhance heavy oil recovery on the Alaska North Slope. According to the authors, the viscous fingering effect in the reservoir during waterflooding and the restoration of injection conformance during polymerflooding were effectively represented. Using the history-matched model, studies were conducted to investigate the oil-recovery performance under different development strategies, with consideration for sensitivity to polymer parameter uncertainties. In paper IPTC 22034, the authors present an approach that incorporates characterization of paleo zones, parameterization of paleo-zone conductivity, and application of flow profiles as a guide in the history-matching study of a conceptual reservoir simulation model under reservoir uncertainty. The authors conclude that the modeled paleo zone acts as a baffle inducing a partial confinement of the injectors. Solving a global optimization problem to minimize the mismatch between the instantaneous shut-in pressure and treatment pressures measured in the field and simulated by the model, for all stages and all wells, is the subject of paper SPE 204162. According to the authors, the technique reduces overfitting by minimizing the number of variables used for history matching, by increasing the number of wells and stages that are simultaneously matched, and by reproducing the dominant behavior of all stages instead of capturing the detailed behavior of specific stages. Recommended additional reading SPE 210224 Rate-Transient-Analysis-Assisted Numerical History Matching and Co-Optimization of CO2 Storage and Huff ’n’ Puff Performance for a Near-Critical Gas Condensate Shale Well by Hamidreza Hamdi, University of Calgary, et al. URTeC 3724391 Fractional Dimension Rate-Transient Analysis in Unconventional Wells: Application in Multiphase Analysis, History Matching, Forecasting, and Interference Evaluation by Behnam Zanganeh, Chevron, et al. SPE 200908 Application of an Integrated Ensemble-Based History-Matching Approach—An Offshore Field Case Study by Usman Aslam, Emerson, et al.

Reservoir Simulation Model Predicts EOR Performance on Alaska’s North Slope

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206247, “History Matching and Performance Prediction of a Polymerflooding Pilot in a Heavy Oil Reservoir on Alaska’s North Slope,” by Xindan Wang, Cody Keith, SPE, and Yin Zhang, University of Alaska Fairbanks, et al. The paper has not been peer reviewed. _ The complete paper discusses the first polymerflooding pilot to enhance heavy oil recovery on the Alaskan North Slope. After more than 2.5 years of polymer injection, significant benefit has been observed from the decrease in water cut, from 65% to less than 15% in project producers. The primary objective of the study was to develop a robust history-matched reservoir simulation model capable of predicting future polymerflooding performance. Pilot Description The pilot program targets an isolated fault block in the Schrader Bluff NB sands with two horizontal injectors (J-23A and J-24A) and two horizontal producers (J-27 and J-28). The producing lengths of the horizontal wells range from 4,200 to 5,500 ft, and the average interwell distance is approximately 1,100 ft. The project wells were put on waterflooding in June 2016, recovering approximately 7.6% of the original oil in place with a cumulative water injection of 0.09 pore volumes (PV). In August 2018, polymer solution injection commenced. The polymer solution, with a target viscosity of 45 cp, was introduced to both injectors by means of a polymer injection unit. By the end of December 2020, a total of 1.7 million STB of polymer solution had been injected, representing 0.08 PV in the flood pattern. A significant benefit of polymerflooding has been observed in the decrease in water cut in both producers. The oil production rate of Producer J-27 (supported by both injectors) increased continuously from 500 to 800 BOPD in April 2019. The oil production rate of Producer J-28 (supported only by J-23A to the north) also increased to approximately 700 BOPD in late 2019 and stabilized at approximately 500 BOPD in 2020. Reservoir Modeling Base Reservoir Model. A 3D reservoir model was developed for the pilot fault block. The selected active reservoir simulation model, including 23,848 active gridblocks, covers the potential sweep area of the project wells. The 3D view of the selected active reservoir simulation model is shown in Fig. 1. The approximate dimensions of the active reservoir simulation model are 6,900, 4,100, and 15 ft in the x, y, and z directions, respectively. The reservoir simulation model consists of eight layers in the z direction. High-Transmissibility Strips. The early water breakthrough and high water cut during the pre-polymer/waterflooding period indicate strong communication and short-circuiting behavior between the injecting and producing wells. To simulate this short-circuiting effect, four high-transmissibility strips at different locations and with different widths were introduced to connect the injectors and producers in the reservoir simulation model. Each strip was present in all eight layers of the model such that the strips in each layer were identical.

Reasons for the viscoelastic compositions breakthrough in the process of polymer flooding pilot testing in the conditions of a complex terrigenous reservoir of the Zaburunye deposit

The article analyzes the viscoelastic compositions breakthrough in the process of polymer flooding pilot testing in the conditions of a complex terrigenous reservoir of the Zaburunye deposit. It was found that a significant increase in the polymers concentration in producing wells is due to the high reserves’ depletion in the sites. It is shown that significant injection volumes, including polymers, as well as the new wells involvement into testing as part of polymer flooding experiment expansion are not environmentally justified, which is due to the high-filtering channels appearance, which are the main cause for physical destruction of polymer chains. To control this phenomenon, a variant of high-viscosity fringes pumping is proposed. Keywords: polymer; water manifestation; system approach; water isolation; oil recovery.

Numerical Simulation of High Concentration Polymer Flooding in Oilfield Development

The field test of high concentration polymer flooding has the characteristics of high cost, long cycle and irreversibility of the reservoir development process. In order to ensure the best development effect of the development block, this paper simulated and calculated the high concentration polymer flooding development case of the polymer flooding pilot test area through numerical simulation research, and selected the best case through the comparison of various development indicators. The simulation results showed that the larger the polymer dosage and the higher the concentration, the better the oil displacement effect. The best injection method in the construction process was the overall injection of high concentration polymer. The test area should implement high concentration polymer oil displacement as soon as possible. The research results provided theoretical guidance for the future development and management of the pilot area.

Polymerflooding Pilot Applied in Lower-Permeability Heterogeneous Sandstone

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200051, “Successful Polymerflood Pilot Application in Lower-Permeability Heterogeneous Sandstone Reservoir in the South of the Sultanate of Oman,” by Hanaa Al-Sulaimani, SPE, Zainab Al-Rawahi, and Conny Velazco Quesada, Petroleum Development Oman, et al. The paper has not been peer reviewed. This paper summarizes the performance of a polymerflooding pilot conducted in an unconsolidated sandstone reservoir in the south of Oman with the objective of extending the envelope of polymerflooding applications to lower-permeability (average 100 md) and highly heterogeneous reservoirs. Fiber-optics data acquisition has demonstrated clearly injection conformance improvement during the switch from water injection to polymer. In addition, approximately 10% of incremental oil recovery was obtained with an average water-cut reversal of 12% across the pattern where the total pattern recovery was greater than 30% (including the waterflood). Introduction Polymerflooding has been ongoing successfully in one of the major fields of southern Oman for almost 10 years. However, the operator aspires to extend the application boundary for the polymer to be applied in lower permeabilities, heavier oils, and different sweep strategies. The field of concern in this paper has an average permeability of 300–500 md, more than four times lower than the average permeability of the field with ongoing polymerflooding. Thus, a polymer pilot was designed to test the applicability of polymer technology in such an environment.

Experimental Investigation of Polymer-Induced Fouling of Heater Tubes in the First-Ever Polymer Flood on Alaska North Slope Part II

Summary A polymer flood pilot has been ongoing in the Schrader Bluff viscous oil reservoir at Milne Point on the Alaska North Slope. The results from the pilot are encouraging. However, a major concern of the operator is the influence of polymer on the production system after breakthrough, especially the fouling in heat exchangers. This work applies a multiexperimental approach to study the severity of polymer-induced fouling in both dynamic and static states of produced fluids to determine safe operating conditions. Dynamic scale loop (DSL) tests were conducted to study fouling due to polymer at different skin temperatures (165–350°F) in a dynamic state of fluid flow where the fluids’ flow mimics the residence time of fluids in the heat exchanger of the field pilot. Static deposit tests were also conducted at similar skin temperatures of 165–250°F using a novel experimental apparatus designed and built in-house. It was found that at higher skin temperatures of 250–350°F, tube blocking was observed in the DSL tests, whereas the tests at 165–200°F did not show any tube blocking, even in a more extended test period. The deposit test showed that the deposit rate generally increases with skin temperature, and the presence of polymer aggravates the fouling. The copper tube performs best when the skin temperatures are 165–200°F, while the stainless steel tube performs best at a skin temperature of 250°F. These experiments also manifested the influence of the cloudpoint of the solution as the deposit rate increased significantly when the skin temperature was higher than the solution cloudpoint. The study provides a source of practical guidance to the field operations.

Emulsification Characteristics and Electrolyte-Optimized Demulsification of Produced Liquid from Polymer Flooding on Alaska North Slope

Summary The first-ever polymer flooding pilot test is currently implemented in heavy oil reservoirs on Alaska North Slope (ANS). One of the major concerns of field engineers is the impact of polymer on oil/water separation after polymer breakthrough. This paper aims to predict the influence of polymer on emulsification characteristics of produced liquid and seek a cost-effective method to treat the produced liquid from polymer flooding. In this study, emulsions, at moderate and vigorous shearing conditions, were prepared by mechanically mixing 25 vol% of the ANS heavy oil with 75 vol% of the polymer solution. Bottle test method, microscope, and pendant drop technique were utilized to investigate the effect of polymer on emulsification characteristics in terms of separation behavior, drop size distribution (DSD), and interfacial properties [i.e., interfacial tension (IFT) and interfacial dilational rheology], respectively. As for chemical demulsification, the performance and interfacial behavior of four commercial demulsifiers and an inorganic salt, that is, potassium chloride (KCl), was measured using simulated produced liquid. The bottle test results demonstrated that polymer could enhance the emulsion stability, resulting in a slower separation rate, poorer water quality, and greater thickness of the intermediate layer. The pendant drop measurements showed that the IFT and interfacial dilational rheology were independent of polymer concentration. Thus, the stabilization effect of the polymer was mainly attributed to the increased viscosity of the continuous phase and the decreased drop size of the dispersed oil phase. As for the chemical demulsification tests, compound demulsifier E12 + E18 exhibited the best demulsification performance as well as the lowest IFT and interfacial elastic modulus. Nevertheless, a multifold dosage of E12 + E18 was required to demulsify the emulsion under vigorous mixing, leading to a potential increase in the chemical cost. A less expensive electrolyte, KCl, was able to work synergistically with demulsifier E12 + E18 to promote oil/water separation and reduce the demulsifier usage. In this proposed demulsifier formula, the mechanism for the effectiveness of the commercial demulsifier was its destructive effect on the interfacial film, while the effectiveness of KCl was mainly dependent on its viscosity reduction effect on the continuous phase. This study illustrates the intermediate layer elimination, and the water quality is the major challenge for produced liquid from polymer flooding and provides both practical and theoretical guidance in advance for the corresponding demulsification strategy of the produced liquid from the ongoing first-ever polymer flooding pilot on ANS.

Offshore Heavy Oil Polymerflooding Pilot Reveals Alternative Paths

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30277, “Twelve-Year Field Applications of Offshore Heavy Oil Polymerflooding From Continuous Injection to Alternating Injection of Polymer and Water,” by Guangming Pan, Lei Zhang, and Jianting Huang, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2-6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Polymerflooding has been considered a suitable method for reservoirs with viscosities up to 150 mPa·s. The authors of the complete paper verify that alternating injection of polymer and water in the Bohai Bay of China proved effective and economical for heavy oil fields, even offshore. This polymerflooding pilot of initially continuous, and then alternating, injection can provide a useful technical reference for similar reservoirs. Introduction Heavy oil reserves are abundant in the Bohai oil field of China. The development of the field has proved that the field with lower viscosity (less than 350 mPa·s) can be developed effectively by water-flooding, while the unconventional heavy oil reservoir with high viscosity has not formed a mature development mode. To better use interwell reserves, a pilot polymerflooding test has been conducted in the NN field since 2008. The cumulative production of nine wells in the surrounding area reached 10.80×104 m3, which confirmed that polymer fluid injection had a good displacement effect on unconventional high-viscosity crude oil. However, with the extension of continuous injection time, the pilot test area faced various problems. In order to explore the applicability of polymerflooding technology used in offshore unconventional heavy oil fields, the polymer-injection mode was studied on the basis of laboratory experimental data and field practice, and the polymer/water alternating injection mode was analyzed. Experimental Continuous Polymerflooding. Experimental Equipment and Materials. The experimental device is composed of a driving system, an experimental model, a pressure-measurement system, a produced-liquid-collection system, and a temperature-control system. According to the distribution of reservoir physical properties in the NN field, a parallel double-tube displacement experiment with a permeability ratio of 5 was designed. The experimental cores are artificial, with a tube length of 30 cm and an inner diameter of 2.54 cm. The low-permeability tube has 1624×10-3 µm2 permeability, and the high-permeability tube has 8488×10-3 µm2 permeability. The experimental temperature is 55°C, which is consistent with the formation temperature of the NN field. The polymer is partially hydrolyzed polyacrylamide. Experimental Procedure. The experimental process includes vacuum pumping, saturating formation water, obtaining core pore volume, saturating simulated oil, calculating oil saturation water drive to a specified water cut, continuously injecting polymer solution, and measuring data. The experimental injection rate is 0.2 mL/min, and the multiple of injected pore volumes (PV) is 0.6 PV. The NN field has weak edge water, and the water cut of the well group was 60 to 90% when polymerflooding was performed. Therefore, the design scheme mainly includes waterflooding and polymerflooding stages. The polymer- injection concentration was 3000 mg/L, and the injection mode is continuous, consistent with the field test.

Optimization Selection Research of Chemical EOR Pilot Project Site for Umm Niqqa Oilfield in Kuwait

The Low Fars of Umm Niqqa oilfield in northern Kuwait is a carbonate formation. After many years of primary and secondary oil recovery, Kuwait Oil Company has started to use chemical EOR flooding technology to increase recovery in this reservoir in recent years, and plans to carry out chemical EOR Pilot project. Due to the dense well pattern and surface facilities in the oil field, the site selection of the pilot project has become a problem. This essay focuses on the optimization method of the pilot project site, underground influencing factors, surface influencing factors, and analysis of the preferred site. Therefore, several important conclusions for selecting the site of the pilot project are summarized: simplifying the site design, combining local geological conditions and construction experience of similar projects, will greatly reduce investment and improve the efficiency of the chemical flooding pilot project. The successful pilot site selection of Umm Niqqa water and polymer flooding pilot projects based on underground design and surface foundation includes well site selection and water source selection. Reserve the surrounding site in advance, drill new wells in this area, install and connect the corresponding water injection pipelines and manifolds to ensure the successful implementation of the chemical flooding pilot project.

Experimental Investigation of Polymer-Induced Fouling of Heater Tubes in the First-Ever Polymer Flood Pilot on Alaska North Slope

Summary Polymer flooding is being pilot tested for the first time in the Schrader Bluff viscous oil reservoir at the Milne Point Field on Alaska North Slope (ANS). One of the major concerns of the operator is the impact of polymer on the oil production system after polymer breakthrough, especially the polymer-induced fouling issues in the heat exchanger. This study investigates the propensity of polymer fouling on the heater tubes as a function of different variables, with the ultimate goal of determining safe and efficient operating conditions. A unique experimental setup was designed and developed in-house to simulate the fouling process on the heating tube. The influence of heating tube skin temperature, tube material, and polymer concentration on fouling tendency was investigated. Each test was run five times with the same tube, and in each run, the freshly prepared synthetic brine and polymer solution was heated from 77°F to 122°F to mimic field-operating conditions. The heating time and fouling amount were recorded for each run. Cloud point measurement has also been conducted to find the critical temperature at which the polymer in solution becomes unstable and precipitates out. The morphology and composition of the deposit samples were analyzed by environmental scanning electron microscopy (ESEM) and X-ray diffraction (XRD), respectively. It was found that the presence of polymer in produced fluids would aggravate the fouling issues on both carbon steel and stainless steel surfaces at all tested skin temperatures. Only higher skin temperatures of 250°F and 350°F could cause polymer-induced fouling issues on the copper tube surface, and the fouling tendency increased with polymer concentration. At the lower skin temperatures of 165°F, no polymer-induced fouling was identified on the copper tube. A critical temperature that is related to the cloud point of the polymer solution was believed to exist, below which polymer-induced fouling would not occur and only mineral scale was deposited but above which the polymer would aggravate the fouling issue. The cloud point of the tested polymer solution was determined to be between 220°F and 230°F. From a practical safer design standpoint, we recommend a value of 220°F for operational purposes on the pilot site. The heating efficiency of the tube would be decreased gradually as more fouling material accumulates on its surface. If polymer precipitated and deposited on the surface, it would bond to the mineral crystals to form a robust three-dimensional network structure, resulting in a rigid polymer-induced fouling. The study results have provided practical guidance to the field operator for the ongoing polymer flooding pilot test on ANS.

Experimental Investigation on Separation Behavior of Heavy-Oil Emulsion for Polymer Flooding on Alaska North Slope

Summary The first-ever field pilot on Alaska North Slope (ANS) to validate using polymer floods for heavy-oil enhanced oil recovery is currently ongoing. One of the major concerns of the operator is the effect of polymer on oil/water-separation efficiency after polymer breakthrough. This work investigates the influence of polymer on the separation behavior of heavy-oil emulsions and evaluates the performance of emulsion breakers (EBs). In this study, two types of heavy-oil emulsions were prepared and tested at 20 and 50% water cut (WC), respectively. The bottle test method was used in the experiments, in which the separated water volume with time, the separated water quality, and the volume fraction of phases were recorded. Results showed that polymer accelerated the oil/water separation acting as an emulsion inhibitor at 20% WC but tended to impede the water separation at 50% WC. Regardless of WC, polymer resulted in poor water quality and the formation of a stable intermediate oil in water (o/w) emulsion, because of the increased viscosity of the water phase. The performance of EBs showed a complex dependency on the WC, the type of demulsifier and dosage, and the polymer concentration. Despite the varied conditions encountered in the heavy-oil/water/polymer/demulsifier system, a compound EB achieved satisfactory demulsification performance, showing the highest potential for deployment in the current ANS polymer flooding pilot. In this paper, we systematically studied the potential influence of polymer breakthrough on the separation behavior of heavy-oil emulsion on ANS for the first time. The findings of this study will provide practical guidance in advance for produced fluid treatment of the ongoing first-ever polymer flooding pilot on ANS.

Interwell EOR Pilot Proves Advantages of Polymer Flooding

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190175, “Results of the UK Captain Field Interwell EOR Pilot,” by Annette Poulsen, SPE, Adam Jackson, SPE, Nicolas Ruby, SPE, and Karl Charvin, Chevron; Michael Shook, Mike Shook and Associates; Varadarajan Dwarakanath, SPE, and Sophany Thach, Chevron; and Mark Ellis, prepared for the 2018 SPE Hydraulic Fracturing Technology Conference, Tulsa, Oklahoma, USA, 14–18. The paper has not been peer reviewed. This paper discusses an enhanced-oil-recovery (EOR) polymer-flood pilot at the Captain field in the UK North Sea during 2011–2013. The polymer flooding accelerated 6 years of potential waterflood recovery to 1 year and minimized potential water injection and handling by 25.2 million STB. A polymer incremental recovery of 16% original oil in place and improved sweep of 4.7 million STB demonstrated the advantage of using polymer EOR for viscous oils. Finally, the pilot data provided sufficient information to deliver a reliable subsurface assessment for the full-field project. These data also provide evidence that chemical-flood pilots not only can be economical but also can compete economically with waterflooding in some challenging locations when designed and operated efficiently. Introduction The Southern Upper Captain Sandstone (SUCS) reservoir is a complex channel in-fill of a localized canyon eroding the underlying Mid Captain Shale (MCS) and Lower Captain Sandstone (LCS). The canyon was created when two megaslump scars merged into a linear valley cut, giving the reservoir its characteristic shape. The slump scar process also triggered deposition of debrites (a mixture of MCS and LCS sediments) of poor reservoir quality, isolating the underlying LCS from the subsequent SUCS canyon fill. Fluids from the Captain field are unlike those normally encountered in black-oil reservoirs. The fluid is a low-gravity oil with a relatively low dissolved-gas/-oil ratio. The oil is heavily biodegraded with some property gradation across the field. There is an apparent general increase in biodegradation from east to west. The oil in the SUCS is analogous to that in the main part of the Upper Captain Sandstone (UCS). Pressure/volume/temperature and special core-analysis laboratory data reveal a highly unfavorable calculated endpoint mobility ratio equal to 31. The following field observations support the adverse mobility ratio: Strong coning tendency Early water breakthrough Modest oil-rate decline Long oil-tail production in waterflood-recovery profiles Sharp oil-saturation changes between unswept and swept regions Injected water slumping to the base of the reservoir, advancing along the base of the sand, and bypassing the oil Pilot Objectives, Mechanisms, and Implementation The polymer flood for the field was originally envisioned in the field- development plan, and the concept was included in the original facilities design to enable a field trial. The major challenge in deploying a polymer flood is field implementation. Though onshore polymer flooding may be considered a mature technology, field experience is difficult to transfer and the offshore environment adds another level of complexity.

Technology Focus: EOR Operations (June 2017)

Technology Focus When I started editing this section in 2015, the year after the oil-price crash, many industry commentators were predicting a strong recovery in oil price by now; instead, the concept of “lower for longer” has become the present reality. Now, many commentators expect a shortfall in supply by the mid-2020s and the effect of shorter-cycle shale oil developments to be just two of the factors affecting price in the future. Sometimes, I hear the view that, without high oil prices, enhanced oil recovery (EOR) does not have a place in the mix of projects delivering the new production needed over the next decade. However, high oil prices are not the whole story. High oil prices may cause an over-heated market that squeezes the value from EOR. By their nature, EOR projects are often longer-term investments, so investing in new EOR projects at a time when real-term costs are at their highest (pushed by the high oil price) may not be the best strategy. Significant progress in cost reduction has been made in the industry following the price downturn, not only in the direct cost of construction and operations but also through a determined drive to simplify and streamline new projects in concepts selected for facilities and wells. Through this competitive scoping, project economics can be improved to deliver more-robust investment opportunities. The discipline of a lower-for-longer world can create the conditions in which long-term investment decisions can be made. In the mix of new projects needed to fill any production shortfall in the coming decade, brownfield improved and enhanced oil recovery can compete with the alternatives available to the industry. SPE continues to play an important role in sharing best practices to allow the industry to reap the benefit of project learnings, and I hope you find that the selected papers and recommended reading provide useful insights. Recommended additional reading at OnePetro: www.onepetro.org. SPE 180755 Enhanced SAGD Startup Techniques for Improved Thermal Efficiency and Conformance—A Field-Test-Based Investigation by J.M. Dragani, Cenovus Energy, et al. SPE 180739 Results of a Polymer-Flooding Pilot in the Tambaredjo Heavy-Oil Field, Suriname by E. Delamaide, IFP Technologies, et al. SPE 183362 Successful Flood-Front and Breakthrough Prediction of Miscible WAG in a Complex Carbonate Reservoir—A Case Study by Z.U.R. Qureshi, ADCO, et al.

Proper Simulation of Chemical-EOR Pilots - A Real Case Study

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179659, “Proper Simulation of Chemical-EOR Pilots—A Real Case Study,” by Nariman Fathi Najafabadi, SPE, and Adwait Chawathe, SPE, Chevron, prepared for the 2016 SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. The paper has not been peer reviewed. A critical step in proper design and optimization of any chemical-enhanced-oil-recovery (CEOR) process is appropriate and precise numerical simulations. Addition of chemical species to the material-balance equations, along with finer resolution requirements for CEOR simulations compared with waterfloods, often makes it impractical to run full-field CEOR simulations to the required accuracy. Sector models, by their definition, are naturally suited for modeling of pilots. This paper presents a case study for appropriate simulation of a CEOR pilot. Introduction Chemical flooding (polymer flooding, surfactant/polymer flooding, and alkali/surfactant/polymer flooding) has improved significantly over the past decade because of vast research efforts to find practical solutions to specific field applications, improvements in the manufacturing and synthesis of new chemicals, field trials, and implementations by the industry. Because of the complexity of CEOR and the inherent uncertainties regarding success of a particular CEOR process, extensive evaluations are required before decisions about full-field implementation can be made. Numerical simulations are critical in CEOR evaluation and provide a realistic performance estimate, assuming that the underlying Earth model is reliable and appropriately calibrated. Usually, chemical floods are performed on candidate fields with a successful water flood history, but CEOR simulations are more complex and challenging compared with water flood modeling and history matching. Sector-Model Generation For the subject asset, which is a brown-field, the primary requirement in CEOR modeling is a representative, quality-controlled waterflood-history-matched full-field (or sector) model. Such a model should replicate the field performance (pressures and flow rates), at least on an overall basis and, preferentially, on a well-by-well basis. The model used for this study had high well density, was sufficiently reliable, and was used routinely for field development and performance prediction. The paper demonstrates the preparation and use of a sector model from this readily available waterflood full-field model for a polymer-flood pilot area. The area of interest (AOI) for the pilot should be selected during an alternatives-analysis phase by a multifunctional team of field engineers and scientists and CEOR subject-matter experts after a project-framing exercise. In this case, this area is a seven-spot pattern containing a central injector and six surrounding producers. This is a small area compared with the full-field model. A local-grid-refinement (LGR) option was considered to create a sufficiently fine grid for CEOR simulation, but the resulting model was still deemed practically prohibitive.

河南油田95℃油藏用聚合物评价与应用

为保证河南油田VII1-3层系高温油藏聚合物驱先导试验的成功，项目在室内系统评价了聚合物性能及聚合物与油藏配伍性能。配制水质、溶液中溶解氧含量、剪切、高温老化等都影响高温聚合物溶液粘度。特别是溶液中溶解氧含量对聚合物粘度长期热稳定性影响显著。氧含量对水解度影响不大。溶解氧含量小于0.5 mg/L条件下，聚合物在95℃高温下老化90天后，结构具有一定的稳定性，拉伸流变稳定性和剪切流变稳定性，老化180 d后粘度保留率可达到80%以上。渗透率为油藏渗透率0.587 μm2，聚合物浓度在1000 - 2000 mg/L范围内，具有较好的注入性。进入矿场应用后，聚合物现场注入性良好，已取得明显的增油降水效果。 In order to ensure the success of polymer flooding pilot test in Henan oilfield VII1-3 formation high temperature reservoir, a lot of tests are researched about the performances of the polymer and its compatibility with the reservoir in the laboratory. These factors influence on the viscosity of polymer solution including water quality, dissolved oxygen content in waste water, shearing, high temperature aging, etc. Especially the dissolved oxygen content in the solution has a great effect on the long-term thermal stability of polymer viscosity. Oxygen content has a little effect on the degree of hydrolysis of polymer. When the dissolved oxygen content is less than 0.5 mg/L, the structure, tensile rheological and shear rheological performance has certain stability in 95˚C high temperature aging 90 days. Aging viscosity retention rate can reach more than 80% after 180 days. It has a good injection within the range 1000 - 2000 mg/L of polymer concentration, when the permeability is 0.587 μm2 of the reservoir. After entering the field application, the polymer injection is good. It has obvious effect of enhanced production of oil and water cut.

Pilot to Full-Field Polymer Application in One of India’s Largest Onshore Fields

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169146, “Pilot to Full-Field Polymer Application in One of the Largest Onshore Fields in India,” by Dhruva Prasad, Amitabh Pandey, SPE, M. Suresh Kumar, and Nitish Koduru, SPE, Cairn India, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12–16 April. The paper has not been peer reviewed. A normal five-spot polymer-flooding pilot has been conducted at the Mangala field, one of the largest onshore fields in India, and results are encouraging in terms of additional oil recovery and reduction of water cut. Polymer flooding has the potential to improve sweep efficiency in the field significantly and to increase expected ultimate recovery (EUR). The project is one of the largest in the world in terms of scale, polymer usage, and related facility and logistics. Introduction The main reservoir unit in Mangala field is the Fatehgarh group. Five reservoir units (FM1–FM5) have been named from the top down. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API higher in the oil column. The crude has an in-situ oil viscosity of 9–22 cp, with live-oil wax-appearance temperature approximately 6°C lower than the average reservoir temperature of 65°C. The oil also has a high pour point of 40–45°C, which had a great influence on all aspects of the project and process design. The development plan involved implementing a hot waterflood from production startup to maintain reservoir pressure and sweep reserves effectively. On the basis of appraisal data, it was realized from the start that Mangala was a candidate for an enhanced-oil-recovery (EOR) process. Detailed laboratory evaluations and simulation studies suggested chemical flooding as the appropriate EOR process for the field. A polymer-flood pilot was conceived on the basis of laboratory and simulation results. The pilot has been successful in terms of reducing water cut and increasing oil rate. Full-field implementation is now planned for Mangala.

Polymer-Flooding-Pilot Learning Curve: Five-Plus Years' Experience To Reduce Cost per Incremental Barrel of Oil

Summary This paper deals with the learning curve of a five-plus-year polymer-flooding pilot conducted in a mature waterflood that includes, for example, several works related to injector and producer wells and reservoir management. The scope of this paper is to describe the learning curve during the last 5 years rather than the reservoir response of the polymer-flooding technique; focus is on the aspects related to reduce cost per incremental barrel of oil for a possible extension to other waterflooded areas of the field. Diadema oil field is in the San Jorge Gulf basin in the southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil-producer company; it has 480 producer and 270 injector wells (interwell spacing is 250 m on average). The company has developed waterflooding over more than 18 years (today, this technique represents 82% of oil production in the field) and produces approximately 1600 m3/d of oil and 40 000 m3/d of gross production (96% water cut) with 38 400 m3/d of water injection. The reservoir that is polymer-flooded is characterized by high permeability (average of 500 md), high heterogeneity (10 to 5,000 md), high porosity (30%), very stratified sandstone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp at reservoir conditions). Diadema's polymer-flooding pilot started in October 2007 on five water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made with produced water (15,000 ppm brine) and 1,500 ppm of hydrolyzed polyacrylamide polymer reaching 15- to 20-cp fluid-injection viscosity. Oil-production rate from the original “central” producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is approximately 15%. The main aspects presented in this work are depth profile modification with crosslinked gel injected along with polymer, use of “curlers” to regulate injection in multiple wells with one injection pump without shearing the polymer, and an improved technology on producer wells with progressing-cavity pumps to decrease shut-in time and number of pump failures. The plan for the future is to extend this project to other areas with the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation. These improvements will allow the company to reduce operating costs per incremental barrel of oil.