Improved polymer flooding injectivity and displacement by considering compositionally-tuned slugs

ABSTRACTIn recent years, polymer flood of heavy oil has been extensively studied in laboratories and successfully applied in several fields. Polymer flooding is the most successful chemical enhanced oil recovery method. However, still, the need for a large amount of polymer, leading to high operational costs, presents a big challenge in technologies. This challenge can be addressed by considering the newly emerging nanomaterials. In this work, the author focuses on roles of TiO2 nanoparticles on polymer viscosity and improve recovery in heavy oil recovery. He present the results obtained from a coreflood experiment with polymer injection in heavy oil at 1320 mPa.sec viscosity. Nanopolymer exhibits an outstanding flow behavior and enhanced oil recovery performance in coreflood displacement tests compared to base polymers. The results indicate that polymer flooding with higher viscosity can significantly improve oil recovery. Flooding test showed about 4% increase in oil recovery for nanopolymer solution in comparison with polymer solution after one pore volume fluid injection.

There are 54 blocks entered into subsequent water flooding period after polymer flooding in Daqing oilfield, The comprehensive water cut is as high as 97.2% and the average oil recovery factor is 57% for the reservoir after polymer flooding, There are 44% geological reserves still remained underground and these reserves are of good quality for further exploitation. But the reservoir has gone through deepen development by tertiary oil recovery and entered into the period of the fourth enhanced oil recovery, so how to further enhance oil recovery is a world's toughest problem. Therefore a new oil displacing system with high efficiency should be developed suitable for the reservoir after polymer flooding in order to greatly enhance oil recovery for ultra-high water cut reservoir after polymer flooding. In this paper, lots of lab experiments have been carried out consisting of oil displacement performance evaluation and formula optimizing. A new ASP formula using associated polymer has been developed, the incremental oil recovery of this system is 10.35% in the lab experiments of natural cores after polymer flooding. In contrast to linear polymer ASP system, associated polymer ASP system can reduce polymer dosage by 48% and increase oil recovery by 3.3% at the same time. The reservoir engineering and oil displacement scenarios have been worked out and the field test has been carried out in the N3D block with 16 injection wells and 25 production wells after polymer flooding in Daqing oilfield. The numerical simulation predicts the incremental oil recovery can reach up to 8.76% after polymer flooding. The test has entered into field and obtained good technological and economic development effect. The blank water flooding began in Sep 2012 and the trial injection of ASP flooding began in Oct 2013 and the main ASP slug began in Jun 2014. Till Oct 2019, the accumulative injection pore volume was 0.9104 PV with the injection pressure increased by 4.7 MPa, water absorption thickness ratio increased by 27.1%, the biggest water cut decline of single well was 6.4% and the staged incremental oil recovery was 7.89%. At present, the accumulative oil production increment is 0.647 million barrels and the economic benefit is 32.35 million dollars. The numerical simulation prediction shows that the final accumulative oil production increment is 0.657 million barrels and the final economic benefit is 32.87 million dollars. This new technology and field test can enhance oil recovery greatly for ultra-high water cut reservoir after polymer flooding and obtain good technological and economic development effect, so it has a broad application prospect and can be applied extensively in ultra-high water cut blocks after polymer flooding in Daqing oilfield.

Reservoirs facing challenges such as high oil viscosity and high heterogeneity benefit from polymer flooding by decreasing unfavorable mobility ratios or improving crossflow. Despite this diversity of needs, polymer floods are often designed around a single point viscosity value, which doesn't account for variable shear rates in the porous media, in-situ viscosity, challenges with fluid injectivity, etc. Polymers have diverse rheological characteristics. For example, synthetic polymers like HPAM are elastic and can range in their degree of shear sensitivity, while biopolymers like scleroglucan are inelastic and highly shear-thinning. We generated laboratory data for two such polymers, scleroglucan and an Acrylamide-ATBS Co-Polymer. We developed parameters to describe their rheological characteristics for a variety of models, including shear thinning, shear thickening and preshearing. We then assessed the impact of these attributes on polymer flooding performance using UTCHEM, the University of Texas Chemical Flooding Reservoir Simulator. Polymer injectivity, viscosity, and shear rate were assessed for sensitivity to polymer rheology using simplified models of radial geometry. These results were correlated to laboratory experiments to ensure correct estimate of in-situ viscosities. Sensitivity to a variety of important parameters, including shear rate correction factor, simulation grid size, shear-thickening, and skin were also completed. A final sensitivity study was conducted using a heterogeneous reservoir model with the multiple patterns. Simulations using the simplified radial model and the heterogeneous, commercial scale model support the same conclusion: the specifics of polymer rheology can have a significant impact on polymer flooding performance, and polymer rheology should be considered an important design attribute along with injection viscosity and retention. We show that injection of an elastic, HPAM-based polymer may require higher injection pressure or lower rates than a highly shear-thinning, inelastic biopolymer like scleroglucan. We also demonstrate how the differences in rheology impact reservoir pressure, in-situ viscosity distribution, in situ shear-rate distribution and flow into various reservoir layers.

Cross-linked polymer flooding can increase oil recovery 10–20% over conventional water flooding, while using a lower concentration of polymer than conventional polymer flooding. Based on production data from a developed oil field, the average incremental oil recovery by polymer flooding is only 10% indicating that much of the oil is bypassed. We need to know how this bypassed oil is distributed to design an optimal development strategy. Numerical simulations have been performed to study the mechanisms of polymer flooding. For the coarsening downward sedimentary cycle, the simulation model was divided into 5 layers with average geometric permeabilities of 100md, 300md, 500md, 980md, and 2190md respectively. Five spot well pattern with 180m distance between each injector and producer has been used. The injecting well was controlled by injection rate of 100m3/d, and shut down as the water ratio reached 98%. Crosslinked polymer injection was introduced after the water cut was as high as 90%, and stopped as the water cut reached 98%. It was found that most of the residual oil after polymer flooding existed in small areas far away from the diagonal line for heterogeneous reservoirs, and in layers with low or intermediate permeabilities for cycle reservoirs. Introduction The Xiaermen oil field lies in Biyang County, Henan Province. It is located in the middle of a large north-east fault edge, to the east of Biyang Sag, Nanxiang Basin (Fig.1). The structure of this field is a brachy-anticline in east-west direction complicated by 4 major faults and many minor faults adjacent to the main oil-bearing area. Among these faults, a series of small faults to the east were originated from the big fault (Fig. 1). The maximum height of the trap is 275m. The Xiaermen sand was deposited by deltaic fans[1]. Considerable variation in sand thickness occurring over short lateral distances is characteristic of this particular deposit and thick layers with high permeability are patchy and isolated. The sediment underlying the project area is finely grained and relatively clean quartz sand. The average porosity is about 24% and the mean geometric permeability is 2 ?? m2. The porosity and permeability is generally high but fairly heterogeneous. The petroleum industry has recognized the problem of inefficient oil recovery by conventional water flooding. Therefore, extensive researches are conducted by use of new techniques to enhance oil recovery (EOR) of the reservoirs[2]. Polymer flooding is a significant method used for this purpose, in which the mobility of the displacing phase can be reduced effectively by the addition of small amounts of water-soluble polymers. Polymer flooding will enhance oil recovery by increasing the water phase viscosity, improving the water / oil mobility ratio and improving sweep efficiency. Polymer flooding may have beneficial effects in relatively homogeneous oil reservoirs. However, the improvements might be more modest in a heterogeneous reservoir.

The number of polymer injection projects has greatly increased worldwide in the past decade, with more and more full-field implementations. More recently, the focus has shifted towards deploying such technologies offshore, which presents specific constraints regarding facilities, logistics, or even produced water treatment. Polymer flooding is an EOR technique that has been widely implemented in China. The oil & gas company SINOPEC has gained extensive experience with polymer while developing the Shengli oil fields. The implementation of polymer flooding in the Chengdao offshore oil field was sanctioned in 2019. This large-scale project has seen polymer injection in 43 wells since October 2020. Polymer flooding helps increase oil production and accelerate recovery by providing a better sweep efficiency as a tertiary oil recovery method. It also results in unique environmental benefits with a reduction in CO2 emissions by 52 to 64% per produced barrel of oil. This project consists in injecting polymer solution in 43 wells with an overall injection rate of 32, 000 bbls/d. Polymer concentration is 3, 000 ppm, and well head injection pressure ranges from 90 barg to 130 barg. Considering the significant polymer volumes, a development with powder form has been selected with f 12 tons/day of nominal consumption. While requiring a larger footprint and slightly more CAPEX, it helped significantly reduce OPEX and transportation costs. In addition, specific equipment and technologies have been selected and implemented to prepare a highly viscous polymer solution, reduce maturation time and prevent any form of chemical or mechanical degradation. This paper will also present recent developments with the use of non-shearing choke valves to avoid significant drop in polymer viscosity. This project is now in operation for 18 months (April 2022) with more than 2, 8 million m3 of polymer solution injection. High injection reliability has been achieved (>98%) for all logistics, operations, and topside equipments. The Chengdao 22F EOR polymer flood pilot project drains an oil-bearing area of 3.21 square kilometers with an estimated initial oil in place (STOIIP) of 80.7 million bbls (12.04 million tons) of which 28.8 million bbls (4.3 million tons) are located within the central producing area. A total of 22 injection and 57 production wells have been drilled. It is predicted that cumulative oil production will reach 28.2 million bbls (4.21 million tons) after 15 years, with an estimated incremental oil recovery factor of 11.6% from polymer injection. Following polymer injection, the water cut start to drop from 90.2% down to 85.0% at few production wells and should continue to drop down to 80%. This paper will provide guidelines to help implementing successfully large-scale chemical EOR projects in an offshore environment. It will also present recent developments in non-shearing choke valves and specific equipment to optimize the injection-facilities’ overall footprint.

SummaryPolymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date.This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator.The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.

Modeling dynamic fracture growth induced by non-Newtonian polymer injection

Displacing viscous oil by water leads to poor displacement efficiency owing to the high mobility ratio and viscous fingering. Polymer injection increases oil recovery by reducing viscous fingering and improving sweep efficiency. We are showing how Alkali-Polymer (AP) flooding is substantially improving production of reactive viscous oil from a Romanian oil field. IFT measurements, coreflood and micro-model experiments were used to understand and optimize the physico-chemical processes leading to incremental oil recovery. Extensive IFT measurements were performed at different alkali and AP concentrations. In addition, phase behavior tests were done. Furthermore, micro-model experiments were used to elucidate effects at the pore-scale and as screening tool for which chemicals to use. Single and two-phase coreflood experiments helped defining the displacement efficiency on a core scale. Various sequences and concentrations of alkali and polymers were injected to reduce costs and maximize incremental recovery of the reactive viscous oil. IFT measurements showed that saponification (110 μmol/g saponifiable acids) at the oil-alkali solution interface is very effectively reducing the IFT. With time, the IFT is increasing owing to diffusion of the generated soaps away from the interface. Phase experiments confirmed that emulsions are formed initially. Micro-models revealed that injection of polymers or alkali only leads to limited incremental oil recovery over waterflooding. For alkali injection, oil is emulsified due to in-situ saponification at the edges of viscous fingers. AP injection after waterflooding is very effective. The emulsified oil at the edges of the viscous fingers is effectively dragged by the viscous fluid substantially increasing recovery. Corefloods confirmed the findings of the micromodels. In addition, the effect of di-valent cations for the selection of the polymer concentration was investigated. Water softening leads to significantly higher viscosity of the AP slug than non-softened brine. Reducing the polymer concentration to obtain the same viscosity as the polymer solution containing divalent cations resulted in similar displacement efficiency. Hence, significant cost savings can be realized for the field conditions, for which AP injection is planned after polymer injection. The results show that alkali solutions lead to initial low IFT of reactive viscous oil owing to soap generation at the oil-alkali solution interface increasing with time due to diffusion. Injecting alkali solutions into reactive viscous oil is not effective to reduce remaining oil saturation, a limited amount of oil is mobilized at the edges of viscous fingers. AP flooding of reactive viscous oil is substantially increasing incremental oil recovery. The reason is the effective dragging of the mobilized oil with the viscous fluid and associated exposure of additional oil to the alkali solutions. Furthermore, the economics of AP flooding projects can be substantially improved by adjusting the polymer concentration to the AP slug containing softened water.

South part of NN reservoir, located at Bohai Bay of China, has reservoir characteristics of complex oil-water contact system, thin single pay zones of 6~8 m and heavy oil viscosity with 413~741mPa·s. At initial natural energy production stage, daily oil of horizontal well reached 21~ 35m3/d. Due to complex oil-water relationship and high formation oil viscosity, oil production rate of whole reservoir decreased from 0.6% to 0.3% after one year. Considering increasing viscosity of injected fluid and reducing the difference of water-oil mobility ratio, polymer flooding with continuous injection mode was carried out since 2008, and its initial good application effect demonstrated polymer flooding was suitable for the thin heavy oil reservoir. However, the problem of gradual decreasing injection ability and oil increment occurred after eight years of continuous injection. A series of physical experiments indicated that profile inversion was inevitable for long PV continuous injection, which results from the difference in the variation of resistance coefficients in high and low permeability zones. The phenomenon of profile inversion was also found in field application by water profile test data over the years. It became critical to inhibit profile inversion for the following injection stage. Two kind of modes including continuous and polymer-water alternate after long PV continuous injection were considered by double tube contrast experiments. Results showed that alternating injection performance was better than continuous injection, low permeability tube had higher oil recovery and larger flow fraction in alternating injection, which demonstrated profile inversion was inhibited in alternating injection mode and more fluid flew in the low permeability tube. After alternate injection was carried out in target reservoir in 2016, the injection rate was increased by 20% because of lower phase viscosity. The average resistance coefficient of alternating mode reached as high as 1.74, which was similar to continuous injection process (2.06). Around the three injection wells, there are nine wells increasing the oil production, and incremental oil production for single well has reached 0.45×104m3~2.12×104m3. The total daily oil production was enhanced by 30%, and the water cut was decreased by 8%. During alternating injection process, polymer agent dosage was reduced by 50%, and operation cost of barrel oil was reduced by 85%, which showed good economic benefit. Polymer flooding has been considered a suitable method for reservoirs with viscosities up to 150 mPa·s. Our practice confirmed again such alternating injection of polymer-water development techniques were also effective and economical for heavy oil fields, even in the offshore oil fields. Polymer flooding pilot of initial continuous and then alternate can provide certain technical reference for similar reservoirs.

Overview Currently available primary- and secondary-oil-production technologies leave behind two-thirds of the oil in place as stranded oil. However, many analysis and field projects have shown that significant oil-recovery increases are possible with improved/enhanced oil recovery (EOR) by gas injection, thermal recovery, or chemical injection. The first two methods have proved cost-effective even at low oil prices. Current oil prices have created renewed interest in more-costly chemical-based EOR methods such as gel treatment, foam flooding, polymer flooding, alkaline/surfactant/polymer (ASP) flooding, and alkaline flooding. This year, we focus on chemical-based EOR methods. Chemical-EOR methods focus on improving the sweep efficiency by correcting reservoir heterogeneity or controlling fluid mobility, or they focus on increasing displacement efficiency by reducing residual-oil saturation. Gel treatment usually is intended to improve sweep efficiency and to reduce excess water production in channeled or fracture-dominated mature reservoirs. A newer trend in gel treatment is to apply preformed gels for in-depth treatments. These gels have been reported to penetrate deeply into superhigh-permeability streaks or fractures and seal or partially seal them off, thus creating high flow resistance in formerly watered-out, high-permeability zones. When successful, these gel systems divert a portion of the injection water into areas not previously swept by water. Foam flooding often is used to reduce gas mobility and to correct reservoir heterogeneity and increase sweep efficiency for gasflooding. Foam can be injected into the reservoir by coinjection of gas and surfactant solution or by injection of surfactant solution alternating with gas (SAG). Foam stability, surfactant-adsorption reduction, and optimized SAG-process design are the keys to controlling the economics of foam flooding. Polymer flooding is designed to control mobility for waterflooding. High-molecular-weight and new high-temperature salt-resistant polymers have made polymer flooding more economical. Adding either an alkaline or surfactant chemical, or both, in a polymer flood will scour residual oil from the rock, resulting in higher oil recovery than with polymer flooding alone. However, the scale problem associated with alkaline limits the use of ASP flooding. Wettability is of major importance to oil recovery, especially for fractured oil-wet carbonate reservoirs where water flows through the fractures but does not imbibe into the matrix because of negative capillary pressure. The chief concern is to develop cost-effective chemical formulations that change the carbonate wettability from oil-wet to water-wet. EOR/IOR additional reading available at the SPE eLibrary: www.spe.org SPE 107095 "Field-Scale Wettability Modification—The Limitations of Diffusive Surfactant Transport" by W.M. Stoll, SPE, Shell International E&P, et al. SPE 107776 "Improved ASP Design Using Organic-Compound/Surfactant/Polymer for La Salina Field, Maracaibo Lake" by E. Guerra, PDVSA Intevep, et al. SPE 107727 "Polymer Flooding: A Sustainable Enhanced Oil Recovery in the Current Scenario" by Ivonete P. Gonzalez da Silva, Petrobras, et al. SPE 106901 "SAGD Optimization With Air Injection" by J.D.M. Belgrave, EnCana Corporation, et al.

This paper provides field scale EOR survey in China which is in line with biennial worldwide EOR survey published by Oil& Gas Journal (OGJ). The EOR progress in China is not available due to language difference and other reasons in OGJ EOR survey. From 2018, EOR survey in China will be published biennially. The first part of this survey mainly focuses on basic information. Chemical flooding, unconventional heavy oil, green recovery and natural gas recovery progress in China will be surveyed and discussed in detail in the other four parts elsewhere. The EOR projects including field tests and field applications in China are summarized in the same pattern as OGJ to the largest extent for better readership outside China. Most data is collected from published journal papers and reports. Different from other countries, there are only four major oil companies in China: CNPC, SINOPEC, CNOOC and Yanchang Oil. The 28 branch companies of these four companies are both operator and owners. Oil and gas production from CNOOC is all offshore. CNPC is the largest oil company in China and its oil production in 2016 accounts for 54% oil production in China. EOR survey in China includes chemical flooding (polymer, SP and ASP flooding, gas flooding (CO2, nitrogen and air), thermal production, MEOR, and foam flooding. EOR production in China in 2016 accounts for 18% total oil production, while chemical EOR accounts for 10 %. Up to present, there has been more than 34 ASP flooding projects in China, most in Daqing. The total ASP oil production in 2016 is 407 million tons. More than 30 SP flooding projects have been carried out, with incremental oil recovery factor of 7%-18% OOIP. More than 170 polymer flooding projects have been carried out. Polymer flooding has been used widely in Daqing, Shengli, Xinjiang, Liaohe, He'nan and Bohai. The incremental oil recovery from polymer flooding and ASP flooding is 7%-15% and 18%-30% OOIP respectively. Gas flooding in China is not as successful as chemical EOR. Polymer flooding production in the largest offshore oilfield in CNOOC accounts for 25% total oil production in 2016. While EOR production in China accounts for 15%-18% in recent years, however, the world EOR oil production only accounts for about 3.3% total oil production. EOR is greatly affected by oil price, as indicated from 26 years EOR content change in America. It is the first time that detailed EOR survey in China in line with worldwide EOR survey in OGJ is given. The EOR survey in China provides valuable and helpful information for engineers and researchers in oil and gas industry.

In-depth gel treatment is a chemical EOR process used to improve the sweep efficiency from heterogeneous reservoirs with crossflow. However, if these reservoirs are saturated with viscous oil, polymer and surfactant flooding should be combined with in-depth gel treatment. Thus, in this study, a 3D model using the UTGEL simulator was built to model in-depth gel treatment combined with surfactant slug and polymer solution. The model was represented by one quarter of the five-spot pattern with eight layers where two thief zones are located in the middle of the model. The thief zones had a permeability of 1500 md with a total thickness of 20 ft, while the rest of the layers had a permeability of 100 md with a total thickness of 200 ft. The gel system consisted of a polyacrylamide/Cr(VI)/thiourea solution, which is considered an in-situ gelation system. Gelant solution was injected for 60 days when the water cut in the model reached 65%, followed by surfactant slug for 2 years, polymer solution for 3 years, and then post-water injection for the rest of the simulation time. The concentrations of the surfactant ranged from 0.01 to 0.2 wt.%, while the polymer concentration was 1,000 ppm. The injection rate was 1,070 bbl/day during all flooding and treatment processes. The results showed that it is imperative to implement surfactant with gel treatment to reduce the interfacial tension between water and oil phases and to alter the wettability of the reservoir rocks. Thus, gel treatment alone or gel followed by polymer was not as efficient as the injection of a surfactant slug. The results also showed that as the reservoir temperature increased, the overall performance of gel, polymer, and surfactant decreased. Therefore, the higher the temperature, the lower the recovery factor. The results also revealed the importance of viscoelastic behavior of the HPAM polymer solution where higher results for both water-wet and oil-wet conditions were obtained compared to shear-thinning behavior only. Moreover, the results revealed interesting behavior regarding the concentration of the surfactant, where the recovery factor increased as the concentration of the surfactant increased in oil-wet conditions. However, in water-wet conditions, the results were unpromising and unfavorable. Furthermore, the injection of surfactant directly after the gel treatment was more effective in improving the sweep efficiency than the injection of polymer directly after the gel treatment. Finally, as the salinity of makeup water and/or reservoir brine increased, the recovery factor decreased for both water and oil-wet systems. This is because, as salinity increased, the adsorption of both polymer and surfactant increased and the polymer viscosity decreased. Furthermore, the presence of divalent cations such as Ca+2 and Mg+2, would have a negative impact on overall treatment.

In the past few years many new (including large-scale) polymer flood projects in heavy oil fields have been implemented and have shown very good success; the Milne Point project in Alaska is just a case in point. The goal of this paper is to provide a review of the current situation for polymer flood in heavy oil fields and explore the potential reasons for their success. This paper is based on a review of the ongoing polymer floods projects in heavy oil fields to obtain a good understanding of the performances that can be expected and indeed have been achieved in the field, and to explore the reasons for the differences in responses. Not only do polymer floods in heavy oil achieve recovery factors that are much higher than expected - up to 50% OOIP @ 1 PV injected in some Canadian cases, but they also provide significant reductions in water consumption and a better carbon footprint than steam-based projects. Moreover, thanks to generations of new polymers, those projects can use any kind of water quality without need for water softening, as opposed to steam-based projects. Polymer injection in heavy oil fields should thus have a bright future. The reasons for the high recoveries are not completely clear and are even more puzzling when considering that these results are achieved with relatively low polymer viscosity - in most cases only 25-50 cP which still corresponds to unfavorable Mobility Ratios. One potential explanation put forward by some authors involves some elements of viscous crossflow and field experience in some cases will be compared to theory to better appreciate the validity of this potential mechanism. A complete review of polymer flood field cases in heavy oil will be presented together with an analysis of the high recoveries achieved with relatively low injected polymer viscosities and some hypotheses for these good performances will be discussed.

Application of polymer flooding in the revitalization of a mature heavy oil field

Patton, J.T., Member AIME, Patton, J.T., Member AIME, Computer/Bioengineering Institute, Inc., Houston, Tex. Coats, K.H., Member AIME, International Computer Applications Ltd., Houston, Tex. Colegrove, G.T., Kelco Co., Houston, Tex. Abstract This experimental and numerical study was performed to estimate the incremental oil recovery performed to estimate the incremental oil recovery by pattern polymer flooding in a California viscous-oil reservoir. Results indicate that adding 270-ppm Kelzan to the normal flood water will boost oil production by 42 percent (at 1 PV injected) and production by 42 percent (at 1 PV injected) and will reduce water handling costs sharply. This corresponds to $8.35 incremental oil/$1.00 polymer injected, taking into account the 30 percent pore volume bank of polymer solution. The 28.6 percent additional oil recovery predicted at 0.5 PV injected yields a return of $4.60 incremental oil/$1.00 polymer injected. polymer injected. The field predictions are based onlaboratory measurements of polymer solution viscosity, adsorption and dispersion upon displacement by normal water in a sand representative of the reservoir,linear laboratory oil displacement experiments using brine and polymer solution, anda numerical model developed to simulate linear or five-spot polymer floods in single-layer or stratified reservoirs. The paper presents an analytical solution to the linear polymer flood problem, which provides a check on accuracy of the numerical model and a quick estimate of additional oil recovery by line-drive polymer floods. The numerical model developed indicates that additional oil recovery by polymer flooding is sensitive to polymer bank size polymer flooding is sensitive to polymer bank size and adsorption level and is insensitive to the extent of dispersion active at the trailing edge of the polymer slug. polymer slug Introduction The benefits of improving the mobility ratio, lambda o/lambda w, on waterflood performance is well documented and research on how best to effect this improvement has been considerable. Both producers and chemical manufacturers, spurred on producers and chemical manufacturers, spurred on by the vast reserves of oil which will be otherwise abandoned, have sought to resolve the problem. Currently, two types of additives are being marketed and field tested with promising results. Both additives increase oil recovery by lowering the mobility of the flood water, lambda w. However, they effect this lowering by distinctly different mechanisms. Mobility of the flood water is given by: lambdaw = kw/ w . Hence, one may elect to either increase viscosity, mu w, or decrease effective permeability, kw. Viscosity can be increased by adding small amounts of a water-soluble polymer. To be effective at the flood front this additive should exhibit minimum adsorption on the pore surfaces. Polymers showing minimal adsorption are generally a combination nonionic-anionic type. The negative charge repels the clay platelets to reduce adsorption and the nonionic portion provides the brine tolerance required for reservoir applications. A polymer of this type, Kelzan M, was chosen for the study. The alternate method of lowering mobility is equally well known. It consists of adding to the flood water a polymer designed to adsorb on the pore surfaces, thereby physically reducing the available flow area. This study was performed to estimate the additional oil recovery by pattern polymer flooding using Kelzan in a California viscous-oil reservoir. Laboratory experiments were performed to estimate polymer solution viscosity, adsorption and polymer solution viscosity, adsorption and dispersion upon displacement by normal injection water. Waterflood and polymer flood oil recovery curves were obtained for a laboratory core packed with sand representative of the reservoir. A numerical model was developed to simulate polymer floods in linear or five-spot patterns in single-layer or stratified reservoirs. An analytical solution to the linear polymer flood problem was developed to provide a quick estimate of incremental oil provide a quick estimate of incremental oil obtainable by polymer flooding and to provide a check on the accuracy of the numerical model. SPEJ P. 72