Relevant bibliographies by topics / Surfactant/polymer flooding

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Academic literature on the topic 'Surfactant/polymer flooding'

Author: Grafiati
Published: 4 June 2021
Last updated: 14 February 2022

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Journal articles on the topic "Surfactant/polymer flooding"

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Nurxat, N., I. Gussenov, G. Tatykhanova, T. Akhmedzhanov, and S. Kudaibergenov. "Alkaline/Surfactant/Polymer (ASP) Flooding." International Journal of Biology and Chemistry 8, no. 1 (2015): 30–42. http://dx.doi.org/10.26577/2218-7979-2015-8-1-30-42.

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Zhou, Haiyan, and Afshin Davarpanah. "Hybrid Chemical Enhanced Oil Recovery Techniques: A Simulation Study." Symmetry 12, no. 7 (July 1, 2020): 1086. http://dx.doi.org/10.3390/sym12071086.

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Simultaneous utilization of surfactant and preformed particle gel (henceforth; PPG) flooding on the oil recovery enhancement has been widely investigated as a preferable enhanced oil recovery technique after the polymer flooding. In this paper, a numerical model is developed to simulate the profound impact of hybrid chemical enhanced oil recovery methods (PPG/polymer/surfactant) in sandstone reservoirs. Moreover, the gel particle conformance control is considered in the developed model after polymer flooding performances on the oil recovery enhancement. To validate the developed model, two sets of experimental field data from Daqing oil field (PPG conformance control after polymer flooding) and Shengli oil field (PPG-surfactant flooding after polymer flooding) are used to check the reliability of the model. Combination of preformed gel particles, polymers and surfactants due to the deformation, swelling, and physicochemical properties of gel particles can mobilize the trapped oil through the porous media to enhance oil recovery factor by blocking the high permeable channels. As a result, PPG conformance control plays an essential role in oil recovery enhancement. Furthermore, experimental data of PPG/polymer/surfactant flooding in the Shengli field and its comparison with the proposed model indicated that the model and experimental field data are in a good agreement. Consequently, the coupled model of surfactant and PPG flooding after polymer flooding performances has led to more recovery factor rather than the basic chemical recovery techniques.
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Han, Xu, Ming Lu, Yixuan Fan, Yuxi Li, and Krister Holmberg. "Recent Developments on Surfactants for Enhanced Oil Recovery." Tenside Surfactants Detergents 58, no. 3 (May 1, 2021): 164–76. http://dx.doi.org/10.1515/tsd-2020-2340.

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Abstract This review discusses surfactants used for chemical flooding, including surfactant-polymer flooding and alkali-surfactant-polymer flooding. The review, unlike most previous reviews in the field, has a surfactant focus, not a focus on the flooding process. It deals with recent results, mainly from 2010 and onward. Older literature is referred to when needed in order to put more recent findings into a perspective.
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Liu, Shunhua, Danhua Zhang, Wei Yan, Maura Puerto, George J. Hirasaki, and Clarence A. Miller. "Favorable Attributes of Alkaline-Surfactant-Polymer Flooding." SPE Journal 13, no. 01 (March 1, 2008): 5–16. http://dx.doi.org/10.2118/99744-pa.

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Summary A laboratory study of the alkaline-surfactant-polymer (ASP) process was conducted. It was found from phase-behavior studies that for a given synthetic surfactant and crude oil containing naphthenic acids, optimal salinity depends only on the ratio of the moles of soap formed from the acids to the moles of synthetic surfactant present. Adsorption of anionic surfactants on carbonate surfaces is reduced substantially by sodium carbonate, but not by sodium hydroxide. The magnitude of the reduction with sodium carbonate decreases with increasing salinity. Particular attention was given to a surfactant blend of a propoxylated sulfate having a slightly branched C16-17 hydrocarbon chain and an internal olefin sulfonate. In contrast to alkyl/aryl sulfonates previously considered for EOR, alkaline solutions of this blend containing neither alcohol nor oil were single-phase micellar solutions at all salinities up to approximately optimal salinity with representative oils. Phase behavior with a west Texas crude oil at ambient temperature in the absence of alcohol was unusual in that colloidal material, perhaps another microemulsion having a higher soap content, was dispersed in the lower-phase microemulsion. Low interfacial tensions existed with the excess oil phase only when this material was present in sufficient amount in the spinning-drop device. Some birefringence was observed near and above optimal conditions. While this phase behavior is somewhat different from the conventional Winsor phase sequence, overall solubilization of oil and brine for this system was high, leading to low interfacial tensions over a wide salinity range and to excellent oil recovery in both dolomite and silica sandpacks. The sandpack experiments were performed with surfactant concentrations as low as 0.2 wt% and at a salinity well below optimal for the injected surfactant. It was necessary that sufficient polymer be present to provide adequate mobility control, and that salinity be below the value at which phase separation occurred in the polymer/surfactant solution. A 1D simulator was developed to model the process. By calculating transport of soap formed from the crude oil and injected surfactant separately, it showed that injection below optimal salinity was successful because a gradient in local soap-to-surfactant ratio developed during the process. This gradient increases robustness of the process in a manner similar to that of a salinity gradient in a conventional surfactant process. Predictions of the simulator were in excellent agreement with the sandpack results. Background Although both injection of surfactants and injection of alkaline solutions to convert naturally occurring naphthenic acids in crude oils to soaps have long been suggested as methods to increase oil recovery, key concepts such as the need to achieve ultralow interfacial tensions and the means for doing so using microemulsions were not clarified until a period of intensive research between approximately 1960 and 1985 (Reed and Healy 1977; Miller and Qutubuddin 1987; Lake 1989). Most of the work during that period was directed toward developing micellar-polymer processes to recover residual oil from sandstone formations using anionic surfactants. However, Nelson et al. (1984) recognized that in most cases the soaps formed by injecting alkali would not be at the "optimal" conditions needed to achieve low tensions. They proposed that a relatively small amount of a suitable surfactant be injected with the alkali so that the surfactant/soap mixture would be optimal at reservoir conditions. With polymer added for mobility control, the process would be an alkaline-surfactant-polymer (ASP) flood. The use of alkali also reduces adsorption of anionic surfactants on sandstones because the high pH reverses the charge of the positively charged clay sites where adsorption occurs. The initial portion of a Shell field test, which did not use polymer, demonstated that residual oil could be displaced by an alkaline-surfactant process (Falls et al. 1994). Several ASP field projects have been conducted with some success in recent years in the US (Vargo et al. 2000; Wyatt et al. 2002). Pilot ASP tests in China have recovered more than 20% OOIP in some cases, but the process has not yet been applied there on a large scale (Chang et al. 2006).
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Cong, Su Nan, and Wei Dong Liu. "Microscopic Displacement Mechanism of Surfactant/Polymer Driving Residual Oil in Conglomerate Reservoir." Advanced Materials Research 301-303 (July 2011): 483–87. http://dx.doi.org/10.4028/www.scientific.net/amr.301-303.483.

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According to microcosmic porous and throats model’s experiment which will be performed in Kexia layer, Qizhong district of conglomerate reservoir in Xinjiang oil fields, microscopic displacement mechanism of surfactant/polymer flooding was researched. Surfactant/polymer flooding has a significant effect on enhancing oil recovery because of the effect from the polymer’s viscosity and the surfactant’s interfacial tension. According to microcosmic porous and throats model’s experiment, the best polymer viscosity and surfactant interfacial tension were determined.
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Sun, Chen, and Yiqiang Li. "Polymer Blocking Distribution and Causes Analysis during Surfactant/Polymer Flooding in Conglomerate Reservoir." International Journal of Chemical Engineering and Applications 7, no. 5 (October 2016): 336–39. http://dx.doi.org/10.18178/ijcea.2016.7.5.601.

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Jiang, Wen Chao, Jian Zhang, Kao Ping Song, En Gao Tang, and Bin Huang. "Study on the Surfactant/Polymer Combination Flooding Relative Permeability Curves in Offshore Heavy Oil Reservoirs." Advanced Materials Research 887-888 (February 2014): 53–56. http://dx.doi.org/10.4028/www.scientific.net/amr.887-888.53.

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Different kinds of compound solutions were prepared by using different concentrations of hydrophobically associating polymers and sulfonate type surfactant. The static viscosity and interfacial tension of these solutions were measured. On the experimental conditions of the Suizhong 36-1 oilfield, the relative permeability curves of the water flooding and the surfactant/polymer combination flooding were measured through the constant speed unsteady method and the experimental data were processed through the way of J.B.N. The several existing kinds of viscosity processing methods of non-newtonian fluid were compared and analysed , and a new way is put forward . The results show that the relative permeability of the flooding phase is very low while displacing the heavy oil; the relative permeability of oil in combination flooding is higher than that in water flooding, the relative permeability of flooding phase in combination flooding is lower than that in water flooding and the residual oil saturation of combination flooding is lower than that of water flooding. Meanwhile, the concentrations of polymer and surfactant have a great influence on the surfactant/polymer combination relative permeability curves.
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Druetta, Pablo, and Francesco Picchioni. "Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding." Energies 13, no. 24 (December 10, 2020): 6520. http://dx.doi.org/10.3390/en13246520.

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The traditional Enhanced Oil Recovery (EOR) processes allow improving the performance of mature oilfields after waterflooding projects. Chemical EOR processes modify different physical properties of the fluids and/or the rock in order to mobilize the oil that remains trapped. Furthermore, combined processes have been proposed to improve the performance, using the properties and synergy of the chemical agents. This paper presents a novel simulator developed for a combined surfactant/polymer flooding in EOR processes. It studies the flow of a two-phase, five-component system (aqueous and organic phases with water, petroleum, surfactant, polymer and salt) in porous media. Polymer and surfactant together affect each other’s interfacial and rheological properties as well as the adsorption rates. This is known in the industry as Surfactant-Polymer Interaction (SPI). The simulations showed that optimum results occur when both chemical agents are injected overlapped, with the polymer in the first place. This procedure decreases the surfactant’s adsorption rates, rendering higher recovery factors. The presence of the salt as fifth component slightly modifies the adsorption rates of both polymer and surfactant, but its influence on the phase behavior allows increasing the surfactant’s sweep efficiency.
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Ding, Lei, Qianhui Wu, Lei Zhang, and Dominique Guérillot. "Application of Fractional Flow Theory for Analytical Modeling of Surfactant Flooding, Polymer Flooding, and Surfactant/Polymer Flooding for Chemical Enhanced Oil Recovery." Water 12, no. 8 (August 4, 2020): 2195. http://dx.doi.org/10.3390/w12082195.

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Fractional flow theory still serves as a powerful tool for validation of numerical reservoir models, understanding of the mechanisms, and interpretation of transport behavior in porous media during the Chemical-Enhanced Oil Recovery (CEOR) process. With the enrichment of CEOR mechanisms, it is important to revisit the application of fractional flow theory to CEOR at this stage. For surfactant flooding, the effects of surfactant adsorption, surfactant partition, initial oil saturation, interfacial tension, and injection slug size have been systematically investigated. In terms of polymer flooding, the effects of polymer viscosity, initial oil saturation, polymer viscoelasticity, slug size, polymer inaccessible pore volume (IPV), and polymer retention are also reviewed extensively. Finally, the fractional flow theory is applied to surfactant/polymer flooding to evaluate its effectiveness in CEOR. This paper provides insight into the CEOR mechanism and serves as an up-to-date reference for analytical modeling of the surfactant flooding, polymer flooding, and surfactant/polymer flooding CEOR process.
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Li, Jierui, Weidong Liu, Guangzhi Liao, Linghui Sun, Sunan Cong, and Ruixuan Jia. "Chemical Migration and Emulsification of Surfactant-Polymer Flooding." Journal of Chemistry 2019 (October 20, 2019): 1–8. http://dx.doi.org/10.1155/2019/3187075.

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With a long sand-packed core with multiple sample points, a laboratory surfactant-polymer flooding experiment was performed to study the emulsification mechanism, chemical migration mechanism, and the chromatographic separation of surfactant-polymer flooding system. After water flooding, the surfactant-polymer flooding with an emulsified system enhances oil recovery by 17.88%. The water cut of produced fluid began to decrease at the injection of 0.4 pore volume (PV) surfactant-polymer slug and got the minimum at 1.2 PV. During the surfactant-polymer flooding process, the loss of polymer is smaller than that of surfactant, the dimensionless breakthrough time of polymer is 1.092 while that of surfactant is 1.308, and the dimensionless equal concentration distance of the chemical is 0.65. During surfactant-polymer flooding, the concentration of surfactant controls the formation of the emulsion. From 50 cm to 600 cm, as the migration distance increases, the concentration of surfactant decreases, and the emulsification strength and duration decrease gradually. With the formation of emulsion, the viscosity of the emulsion is relatively stable, which is beneficial to enhanced oil recovery. With the shear of reservoirs and migration of surfactant-polymer slug, the emulsion is formed to improve the swept volume and sweep efficiency and enhance oil recovery.
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Dissertations / Theses on the topic "Surfactant/polymer flooding"

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Alkhatib, Ali. "Decision making and uncertainty quantification for surfactant-polymer flooding." Thesis, Imperial College London, 2013. http://hdl.handle.net/10044/1/22154.

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The aim of this thesis is to develop a robust parametric uncertainty quantification method and a decision making method for a chemical EOR process. The main motivation is that uncertainty is detrimental to the wide scale implementation of chemical EOR. Poor scale-up performance is not in line with the success in laboratory applications. Furthermore, economic uncertainty is also an important factor as low oil prices can deter EOR investment. As an example of chemical EOR we used Surfactant-polymer flooding due to its high potential and complexity. The approach was based on using Value of Flexibility evaluation in order to optimize the surfactant-polymer flooding in the presence of economic and technical uncertainty. This method was inspired by real options theory which provides a framework to value flexibility and captures the effect of uncertainty as the process evolves through time. By doing so, it provides the means to capitalize on the upside opportunities that these uncertainties present or to help mitigate worsening circumstances. In addition, it fulfils a secondary objective to develop a decision making process that combines both technical and economic uncertainty. The Least Squares Monte Carlo (LSM) method was chosen to value flexibility in surfactant-polymer flooding. The algorithm depends on two main components; the stochastic simulation of the input state variables and the dynamic programming approach that produce the optimal policy. The produced optimal policy represents the influence of uncertainty in the time series of the relevant input parameters. Different chemical related parameters were modelled stochastically such as surfactant and polymer adsorption rates and residual oil saturation. Static uncertainty in heterogeneity was incorporated using Gaussian and multiple-point statistics generated grids and dynamic uncertainty in heterogeneity was modelled using upscaling techniques. Economic uncertainties such as the oil price and surfactant and polymer cost were incorporated into the model as well. The results obtained for the initial case studies showed that the method produced higher value compared with static policy scenarios. It showed that by designing flexibility into the implementation of the surfactant-polymer flood, it is possible to create value in the presence of uncertainty. An attempt to enhance the performance of the LSM algorithm was introduced by using the probabilistic collocation method (PCM) to sample the distributions of the technical state input parameters more efficiently, requiring significantly less computational time compared to Monte Carlo sampling. The combined approach was then applied to more complex decisions to demonstrate its scalability. It was found that the LSM algorithm could value flexibility for surfactant-polymer flooding and that it introduces a new approach to highly uncertain problems. However, there are some limitations to the extendibility of the algorithm to more complex higher dimensional problems. The main limitation was observed when using a finer discretization of the decision space because it requires a significant increase in the number of stochastic realization for the results to converge, thus increasing the computational requirement significantly. The contributions of this thesis can be summarized into the following: an attempt to use real options theory to value flexibility in SP flooding processes, the development of an approximate dynamic programming approach to produce optimal policies, the robust quantification of parametric uncertainty for SP flooding using PCM and an attempt to improve the efficiency of the LSM method by coupling it with the PCM code in order to extend its applicability to more complex problems.
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Elias, Samya Daniela de Sousa. "Synthesis of a high performance surfactant for application in alkaline-surfactant-polymer flooding in extreme reservoirs." Thesis, Cape Peninsula University of Technology, 2016. http://hdl.handle.net/20.500.11838/2491.

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Thesis (MTech (Chemical Engineering))--Cape Peninsula University of Technology, 2016.
Due to the rising cost involve with bringing new fields on stream, of producing residual crude from matured fields, and the significant enhancement in oil recovery provided when compared to conventional water-flooding, increasing attention is being given to chemical flooding technologies. This is particular of interest in mature fields that had previously undergone water flooding. These methods entail injecting chemicals such as surfactant, alkali, and polymer often in mixture into reservoirs to improve oil recovery. In this study a sulfonated surfactant was produced from cheap waste vegetable oils and its performance was assessed in terms of thermal stability at reservoir conditions, adsorption on different reservoir materials, gas chromatography characterization and a limited interfacial tension measurement to evaluate its ability to improve the recovery of crude oil. Waste vegetable oils have great potential as a sustainable and low cost feedstock as well as its low toxicity.
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Awolola, Kazeem Adetayo. "ENHANCED OIL RECOVERY FOR NORNE FIELD (STATOIL) C-SEGMENT USING ALKALINE-SURFACTANT-POLYMER FLOODING." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19259.

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A great percentage of oil is observed to be left in the reservoir after the traditional primary and secondary recovery methods. This oil is described as immobile oil. Alkaline-Surfactants are chemicals used to reduce the interfacial tension between the involved fluids, while polymer is used in making the immobile oil mobile.Norne C-segment is in the decline stage and is facing considerable challenges regardingvolume of oil bye-passed due to water flooding. There is need for developing cost efficient enhanced oil recovery (EOR) methods that would be suitable for Norne fluid and rock properties and therefore improve sweep efficiency significantly. Based on literature and screening criteria, alkaline-surfactant-polymer can be used as an enhancing agent to produce extra oil and reduce water-cut significantly in the C-segment.The objective of this work is to evaluate the possibilities of using alkaline, surfactant and/or polymer to increase the oil recovery factor and prolong the production decline stage of Norne field. An initial study was conducted using heterogeneous synthetic models (with Norne Csegment fluids and rock properties) to assess the suitability of alkaline/surfactant/polymer (ASP) flooding. All the chemical cases simulated gave substantial incremental oil production and water-cut reduction. However, history matched Norne C-segment reservoir model was used to simulate alkalinesurfactant-polymer flooding using Eclipse 100. Appropriate chemical quantity for injection was ascertained by simulating several cases with different concentration, injection length and time of injection. Different sensitivity analyses were made and simulations revealed that the most effective method was not the most profitable. Having established most profitable method which was injecting ASP slug with a concentration of 7Kg/m3, 2Kg/m3 and 0.3Kg/m3 into C-3H (injector) for 4-years in a cyclic manner, an incremental recovery factor of 2.61% was recorded and Net Present Value (NPV) was calculated to be 1660 x103MNOK
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Abadli, Farid. "Simulation Study of Enhanced Oil Recovery by ASP (Alkaline, Surfactant and Polymer) Flooding for Norne Field C-segment." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19432.

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This research is a simulation study to improve total oil production using ASP flooding method based on simulation model of Norne field C-segment. The black oil model was used for simulations. Remaining oil in the reservoir can be divided into two classes, firstly residual oil to the water flood and secondly oil bypassed by the water flood. Residual oil mainly contains capillary trapped oil. Water flooding only is not able to produce capillary trapped oil so that there is a need for additional technique and force to produce as much as residual oil. One way of recovering this capillary trapped oil is by adding chemicals such as surfactant and alkaline to the injected water. Surfactants are considered for enhanced oil recovery by reduction of oil–water interfacial tension (IFT). The crucial role of alkali in an alkaline surfactant process is to reduce adsorption of surfactant during displacement through the formation. Also alkali is beneficial for reduction of oil-water IFT by in situ generation of soap, which is an anionic surfactant. Generally alkali is injected with surfactant together. On the other hand, polymer is very effective addition by increasing water viscosity which controls water mobility thus improving the sweep efficiency.In the first place, ASP flooding was simulated and studied for one dimensional, two dimensional and three dimensional synthetic models. All these models were built based on C-segment rock properties and reservoir parameters. Based on test runs, well C-3H was selected and used as a main injector in order to execute chemical injection schemes in the C-segment. Five studies such as polymer flooding, surfactant flooding, surfactant-polymer flooding, alkaline-surfactant and alkaline-surfactant-polymer flooding were considered in the injection process and important results from simulator were analyzed and interpreted. Sensitivity analyses were done especially focusing on chemical solution concentration, injection rate and duration of injection time. The polymer flooding project in this study has shown a better outcome compared to water flooding project. Economically best ASP solution flooding case is the flooding with concentration of alkaline at1.5kg/m3, surfactant at 15kg/m3 and polymer at 0.35 kg/m3 injecting for 5 years. AS flooding case for 4 years with alkali concentration at 0.5kg/m3 and surfactant concentration at 25 kg/m3 gave highest NPV value. It was found that surfactant flooding has a promising effect and it is more profitable than polymer flooding for the C segment in terms of NPV. Economic sensitivity analysis (Spider diagram) for low case, base case and high case at different oil prices, chemicals prices, and discount rate were also presented. It was found that change in oil price has significant effect on NPV compared to other parameters while polymer price has the least effect on NPV for high and low cases.
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Sarkar, Sume. "Evaluation of Alkaline, Surfactant and Polymer Flooding for Enhanced Oil Recovery in the Norne E-segment Based on Applied Reservoir Simulation." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19958.

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The world needs energy – and over the short and medium term it is clear that much of our global energy consumption will come from fossil sources such as oil, gas and coal. With the current growing demand for oil led by major energy consuming countries such as China and India, securing new oil resources is a critical challenge for the oil industry. Each year, new production is needed to compensate the natural decline of existing wells, and the additional production required to satisfy the yearly demand for hydrocarbon energy that will represent approximately 9% of the worldwide total production. For this growth to be sustainable, a strong focus will have to be placed on finding new discoveries and/or optimizing oil production from current resources. The cost associated with the first option is significant. Therefore, reservoir management teams all over the world will have to cater for this demand mainly by maximizing hydrocarbon recovery factors through Enhanced Oil Recovery (EOR) processes. EOR consists of methods aimed at increasing ultimate oil recovery by injecting appropriate agents not normally present in the reservoir, such as chemicals, solvents, oxidizers and heat carriers in order to induce new mechanisms for displacing oil. Chemical flooding is one of the most promising and broadly applied EOR processes which have enjoyed significant research and pilot testing during the 1980s with a significant revival in recent years. However, its commercial implementation has been facing several technical, operational and economic challenges. Chemical flooding is further subdivided into polymer flooding, surfactant flooding, alkaline flooding, miscellar flooding, alkaline-surfactant-polymer (ASP) flooding. ASP flooding is a form of chemical enhanced oil recovery (EOR) that can allow operators to extend reservoir pool life and extract incremental reserves currently inaccessible by conventional EOR techniques such as waterflooding. Three chemical inject in the ASP process which is synergistic. In the ASP process, Surfactants are chemicals that used to reduce the interfacial tension between the involved fluids, making the immobile oil mobile. Alkali reduces adsorption of the surfactant on the rock surfaces and reacts with acids in the oil to create natural surfactant. Polymer improves the sweep efficiency. By simulating ASP flooding for several cases, with different chemical concentrations, injection length, time of injection, current well optimization and new well placement, this report suggests a number of good alternatives. Simulations showed that the most effective method was not the most profitable. From the simulation results and economic analysis, ASP flooding can be a good alternative for the Norne E-segment. But the margins are not significant, so fixed costs (such as equipment rental) will be of crucial importance.
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(5930765), Pratik Kiranrao Naik. "History matching of surfactant-polymer flooding." Thesis, 2019.

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This thesis presents a framework for history matching and model calibration of surfactant-polymer (SP) flooding. At first, a high-fidelity mechanistic SP flood model is constructed by performing extensive lab-scale experiments on Berea cores. Then, incorporating Sobol based sensitivity analysis, polynomial chaos expansion based surrogate modelling (PCE-proxy) and Genetic algorithm based inverse optimization, an optimized model parameter set is determined by minimizing the miss-fit between PCE-proxy response and experimental observations for quantities of interests such as cumulative oil recovery and pressure profile. The epistemic uncertainty in PCE-proxy is quantified using a Gaussian regression process called Kriging. The framework is then extended to Bayesian calibration where the posterior of model parameters is inferred by directly sampling from it using Markov chain Monte Carlo (MCMC). Finally, a stochastic multi-objective optimization problem is posed under uncertainties in model parameters and oil price which is solved using a variant of Bayesian global optimization routine.
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Yuan, Changli. "Commercial scale simulations of surfactant/polymer flooding." Thesis, 2012. http://hdl.handle.net/2152/ETD-UT-2012-08-401.

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The depletion of oil reserves and higher oil prices has made chemical enhanced oil recovery (EOR) methods more attractive in recent years. Because of geological heterogeneity, unfavorable mobility ratio, and capillary forces, conventional oil recovery (including water flooding) leaves behind much oil in reservoir, often as much as 70% OOIP (original oil in place). Surfactant/polymer flooding targets these bypassed oil left after waterflood by reducing water mobility and oil/water interfacial tension. The complexity and uncertainty of reservoir characterization make the design and implementation of a robust and effective surfactant/polymer flooding to be quite challenging. Accurate numerical simulation prior to the field surfactant/polymer flooding is essential for a successful design and implementation of surfactant/polymer flooding. A recently developed unified polymer viscosity model was implemented into our existing polymer module within our in-house reservoir simulator, the Implicit Parallel Accurate Reservoir Simulator (IPARS). The new viscosity model is capable of simulating not only the Newtonian and shear-thinning rheology of polymer solution but also the shear-thickening behavior, which may occur near the wellbore with high injection rates when high molecular weight Partially Hydrolyzed Acrylamide (HPAM) polymers are injected. We have added a full capability of surfactant/polymer flooding to TRCHEM module of IPARS using a simplified but mechanistic and user-friendly approach for modeling surfactant/water/oil phase behavior. The features of surfactant module include: 1) surfactant component transport in porous media; 2) surfactant adsorption on the rock; 3) surfactant/oil/water phase behavior transitioned with salinity of Type II(-), Type III, and Type II(+) phase behaviors; 4) compositional microemulsion phase viscosity correlation and 5) relative permeabilities based on the trapping number. With the parallel capability of IPARS, commercial scale simulation of surfactant/polymer flooding becomes practical and affordable. Several numerical examples are presented in this dissertation. The results of surfactant/polymer flood are verified by comparing with the results obtained from UTCHEM, a three-dimensional chemical flood simulator developed at the University of Texas at Austin. The parallel capability and scalability are also demonstrated.
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Mohammadi, Hourshad 1977. "Mechanistic modeling, design, and optimization of alkaline/surfactant/polymer flooding." 2008. http://hdl.handle.net/2152/18190.

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Alkaline/surfactant/polymer (ASP) flooding is of increasing interest and importance because of high oil prices and the need to increase oil production. The benefits of combining alkali with surfactant are well established. The alkali has very important benefits such as lowering interfacial tension and reducing adsorption of anionic surfactants that decrease costs and make ASP a very attractive enhanced oil recovery method provided the consumption is not too large and the alkali can be propagated at the same rate as a synthetic surfactant and polymer. However, the process is complex so it is important that new candidates for ASP be selected taking into account the numerous chemical reactions that occur in the reservoir. The reaction of acid and alkali to generate soap and its subsequent effect on phase behavior is the most crucial for crude oils containing naphthenic acids. Using numerical models, the process can be designed and optimized to ensure the proper propagation of alkali and effective soap and surfactant concentrations to promote low interfacial tension and a favorable salinity gradient. The first step in this investigation was to determine what geochemical reactions have the most impact on ASP flooding under different reservoir conditions and to quantify the consumption of alkali by different mechanisms. We describe the ASP module of UTCHEM simulator with particular attention to phase behavior and the effect of soap on optimum salinity and solubilization ratio. Several phase behavior measurements for a variety of surfactant formulations and crude oils were successfully modeled. The phase behavior results for sodium carbonate, blends of surfactants with an acidic crude oil followed the conventional Winsor phase transition with significant three-phase regions even at low surfactant concentrations. The solubilization data at different oil concentrations were successfully modeled using Hand's rule. Optimum salinity and solubilization ratio were correlated with soap mole fractions using mixing rules. New ASP corefloods were successfully modeled taking into account the aqueous reactions, alkali/rock interactions, and the phase behavior of soap and surfactant. These corefloods were performed in different sandstone cores with several chemical formulations, crude oils with a wide range of acid numbers, brine with a wide range of salinities, and a wide range of temperatures. 2D and 3D sector model ASP simulations were performed based on field data and design parameters obtained from coreflood history matches. The phenomena modeled included aqueous phase chemical reactions of the alkaline agent and consequent consumption of alkali, the in-situ generation of surfactant by reaction with the acid in the crude, surfactant/soap phase behavior, reduction of surfactant adsorption at high pH, cation exchange with clay, and the effect of co-solvent on phase behavior. Sensitivity simulations on chemical design parameters such as mass of surfactant and uncertain reservoir parameters such as kv/kh ratio were performed to provide insight as the importance of each of these variables in chemical oil recovery. Simulations with different permeability realizations provided the range for chemical oil recoveries. This study showed that it is very important to model both surface active components and their effect on phase behavior when doing mechanistic ASP simulations. The reactions between the alkali and the minerals in the formation depend very much on which alkali is used, the minerals in the formation, and the temperature. This research helped us increase our understanding on the process of ASP flooding. In general, these mechanistic simulations gave insights into the propagation of alkali, soap, and surfactant in the core and aid in future coreflood and field scale ASP designs.
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Wang, Like active 2013. "A study of offshore viscous oil production by polymer flooding." 2013. http://hdl.handle.net/2152/22550.

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Due to capillary pressure, reservoir heterogeneity, oil mobility, and lack of reservoir energy, typically more than 50 % of the original oil in place is left in the reservoir after primary and secondary recovery oil production. With relatively easy-to-get conventional oil resources diminishing and the price of oil hovering around triple digits, enhanced oil recovery methods, such as polymer flooding, have become very attractive ways to recover oil effectively from existing reservoirs. Enhanced oil recovery methods can be categorized into three categories: water or chemical based, gas based, and thermal based. This thesis will focus on the chemical injection of surfactants, alkali, and polymer of the water based methods. Surfactants are used to alter the interfacial tension of the aqueous and oleic phases in order to facility oil production. Alkali chemicals are used to create surfactants by reacting with acidic oil. And polymer is used to reduce injection water mobility to effectively displace the contacted oil in heterogeneous reservoirs by improving the volumetric and displacement sweep efficiencies. This research presents several laboratory results of polymer and alkali/surfactant/polymer core floods performed in the Center for Petroleum and Geosystems Engineering laboratories. Properties of polymer and surfactant phase behavior were measured and modeled and each coreflood was history matched with UTCHEM, a three-dimensional chemical flooding simulator. The coreflood results and the history matched model parameters were then upscaled to a pilot case for viscous oil in offshore environment with four wells in a line drive pattern. The potential of polymer flooding was investigated and several sensitivity cases were performed to evaluate the effect of various physical property parameters on oil recovery. Water salinity and hardness (i.e. amount of calcium and magnesium) has detrimental effects on polymer viscosity and its stability. The potential benefits of low salinity water injection by desalinization of seawater for polymer flood projects have been discussed in recent publications. The effect of low salinity polymer flood was also investigated. A series of sensitivity studies on well pattern and well spacing is carried out to investigate the impact on recovery factor and recovery time.
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Koyassan, Veedu Faiz. "Scale-up methodology for chemical flooding." Thesis, 2010. http://hdl.handle.net/2152/ETD-UT-2010-12-2578.

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Accurate simulation of chemical flooding requires a detailed understanding of numerous complex mechanisms and model parameters where grid size has a substantial impact upon results. In this research we show the effect of grid size on parameters such as phase behavior, interfacial tension, surfactant dilution and salinity gradient for chemical flooding of a very heterogeneous oil reservoir. The effective propagation of the surfactant slug in the reservoir is of paramount importance and the salinity gradient is a key factor in ensuring the process effectiveness. The larger the grid block size, the greater the surfactant dilution, which in turn erroneously reduces the effectiveness of the process indicated with low simulated oil recoveries. We show that the salinity gradient is not adequately captured by coarse grid simulations of heterogeneous reservoirs and this leads to performance predictions with lower recovery compared to fine grid simulations. Due to the highly coupled, nonlinear interactions of the many chemical and physical processes involved in chemical flooding, it is better to use fine-grid simulations rather than coarse grids with upscaled physical properties whenever feasible. However, the upscaling methodology for chemical flooding presented in this work accounts approximately for some of the more important effects, as demonstrated by comparison of fine grid and coarse grid results and is very different than the way other enhanced oil recovery methods are upscaled. This is a step towards making better performance predictions of chemical flooding for large field projects where it is not currently feasible to perform the large number of simulations required to properly consider different designs, optimization, risk and uncertainty using fine-grid simulations.
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Books on the topic "Surfactant/polymer flooding"

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Engineers, Society Of Petroleum. Surfactant/Polymer Chemical Flooding-I. Society of Petroleum Engineers, 1988.

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Engineers, Society of Petroleum. Surfactant/Polymer Chemical Flooding-II. SPE, 1988.

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Surfactant Polymer Chemical Flooding (Cat No 30555). Society of Petroleum, 1988.

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Book chapters on the topic "Surfactant/polymer flooding"

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Danaev, Nargozy, Darkhan Akhmed-Zaki, Saltanbek Mukhambetzhanov, and Timur Imankulov. "Mathematical Modelling of Oil Recovery by Polymer/Surfactant Flooding." In Communications in Computer and Information Science, 1–12. Cham: Springer International Publishing, 2015. http://dx.doi.org/10.1007/978-3-319-25058-8_1.

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Wang, Tao, Caili Dai, Mingwei Zhao, Qing You, and Quanyi Wen. "Experimental Study of Organic Alkali Enhancing Polymer/Surfactant Flooding Oil Recovery." In Springer Series in Geomechanics and Geoengineering, 1114–26. Singapore: Springer Singapore, 2018. http://dx.doi.org/10.1007/978-981-10-7560-5_102.

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Han, P. H., R. B. Cao, H. S. Liu, W. Yan, L. Yang, F. Luo, and H. Zhou. "Post-flooding with Associative Polymer/Alkali/Surfactant Ternary System After Polymer-Enhanced Oil Recovery." In Proceedings of the International Field Exploration and Development Conference 2018, 1264–74. Singapore: Springer Singapore, 2019. http://dx.doi.org/10.1007/978-981-13-7127-1_119.

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Bhatkar, Siraj, and Lalitkumar Kshirsagar. "An Experimental Study of Dynamic Adsorption of Polymer in Alkaline Surfactant Polymer (ASP) Flooding for Heavy Oil." In Techno-Societal 2020, 853–60. Cham: Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-69925-3_81.

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Zhang, Jie, Yong-hong Wang, Yang-nan Shangguan, Guo-wei Yuan, Yong-qiang Zhang, Wei-liang Xiong, Jin-long Yang, Li-li Wang, and Shuan-lian Jin. "Optimization Study of Polymer-Surfactant Binary Flooding Parameters in Maling Jurassic Low Permeability Reservoir." In Proceedings of the International Petroleum and Petrochemical Technology Conference 2020, 173–82. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-1123-0_18.

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Sheng, James J. "Surfactant-Polymer Flooding." In Modern Chemical Enhanced Oil Recovery, 371–87. Elsevier, 2011. http://dx.doi.org/10.1016/b978-1-85617-745-0.00009-7.

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Sheng, James J. "Surfactant–Polymer Flooding." In Enhanced Oil Recovery Field Case Studies, 117–42. Elsevier, 2013. http://dx.doi.org/10.1016/b978-0-12-386545-8.00005-1.

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Sheng, James J. "Alkaline-Surfactant-Polymer Flooding." In Modern Chemical Enhanced Oil Recovery, 501–67. Elsevier, 2011. http://dx.doi.org/10.1016/b978-1-85617-745-0.00013-9.

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Ragab, Ahmed, and Eman M. Mansour. "Enhanced Oil Recovery: Chemical Flooding." In Geophysics and Ocean Waves Studies. IntechOpen, 2021. http://dx.doi.org/10.5772/intechopen.90335.

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The enhanced oil recovery phase of oil reservoirs production usually comes after the water/gas injection (secondary recovery) phase. The main objective of EOR application is to mobilize the remaining oil through enhancing the oil displacement and volumetric sweep efficiency. The oil displacement efficiency enhances by reducing the oil viscosity and/or by reducing the interfacial tension, while the volumetric sweep efficiency improves by developing a favorable mobility ratio between the displacing fluid and the remaining oil. It is important to identify remaining oil and the production mechanisms that are necessary to improve oil recovery prior to implementing an EOR phase. Chemical enhanced oil recovery is one of the major EOR methods that reduces the residual oil saturation by lowering water-oil interfacial tension (surfactant/alkaline) and increases the volumetric sweep efficiency by reducing the water-oil mobility ratio (polymer). In this chapter, the basic mechanisms of different chemical methods have been discussed including the interactions of different chemicals with the reservoir rocks and fluids. In addition, an up-to-date status of chemical flooding at the laboratory scale, pilot projects and field applications have been reported.
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El-hoshoudy, Abdelaziz N., Saad M. Desouky, Mohamed H. Betiha, and Ahmed M. Alsabagh. "Hydrophobic Polymers Flooding." In Application and Characterization of Surfactants. InTech, 2017. http://dx.doi.org/10.5772/intechopen.69645.

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Conference papers on the topic "Surfactant/polymer flooding"

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Yang, C. Z. "Adjustment of Surfactant/Polymer Interaction in Surfactant/Polymer Flooding With Polyelectrolytes." In SPE Enhanced Oil Recovery Symposium. Society of Petroleum Engineers, 1986. http://dx.doi.org/10.2118/14931-ms.

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Wang, Jinxun, Ming Han, Alhasan B. Fuseni, and Dongqing Cao. "Surfactant Adsorption in Surfactant-Polymer Flooding for Carbonate Reservoirs." In SPE Middle East Oil & Gas Show and Conference. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/172700-ms.

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Al Kalbani, M. M., M. M. Jordan, E. J. Mackay, K. S. Sorbie, and L. Nghiem. "Barium Sulphate Scaling and Control during Polymer, Surfactant and Surfactant-Polymer Flooding." In SPE International Conference on Oilfield Chemistry. Society of Petroleum Engineers, 2019. http://dx.doi.org/10.2118/193575-ms.

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Wang, Yefei, Fulin Zhao, and Baojun Bai. "Optimized Surfactant IFT and Polymer Viscosity for Surfactant-Polymer Flooding in Heterogeneous Formations." In SPE Improved Oil Recovery Symposium. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/127391-ms.

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Rai, Khyati, Russell Taylor Johns, Larry Wayne Lake, and Mojdeh Delshad. "Oil-Recovery Predictions for Surfactant Polymer Flooding." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/124001-ms.

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Zhang, Danhua, Shunhua Liu, Wei Yan, Maura Puerto, George J. Hirasaki, and Clarence A. Miller. "Favorable Attributes of Alkali-Surfactant-Polymer Flooding." In SPE/DOE Symposium on Improved Oil Recovery. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/99744-ms.

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Lüftenegger, Markus, and Torsten Clemens. "Chromatography Effects in Alkali Surfactant Polymer Flooding." In SPE Europec featured at 79th EAGE Conference and Exhibition. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/185793-ms.

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Felix, Uwari, Taiwo Oluwaseun Ayodele, and Olafuyi Olalekan. "Surfactant-Polymer Flooding Schemes (A Comparative Analysis)." In SPE Nigeria Annual International Conference and Exhibition. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/178367-ms.

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Ahmed, Hassaan, Abeeb A. Awotunde, Abdullah S. Sultan, and Hasan Y. Al-Yousef. "Stochastic Optimization Approach To Surfactant-Polymer Flooding." In SPE/PAPG Pakistan Section Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/191294-ms.

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Yuan, Shiyi, Puhua Yang, Zhongqiu Dai, and Kuiyou Shen. "Numerical Simulation of Alkali/Surfactant/Polymer Flooding." In International Meeting on Petroleum Engineering. Society of Petroleum Engineers, 1995. http://dx.doi.org/10.2118/29904-ms.

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Reports on the topic "Surfactant/polymer flooding"

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French, T. R., and C. B. Josephson. The effect of polymer-surfactant interaction on the rheological properties of surfactant enhanced alkaline flooding formulations. Office of Scientific and Technical Information (OSTI), February 1993. http://dx.doi.org/10.2172/10130748.

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Lorenz, Philip B. Correlation of laboratory design procedures with field performance in surfactant-polymer flooding. Office of Scientific and Technical Information (OSTI), February 1989. http://dx.doi.org/10.2172/6133902.

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French, T. R., and C. B. Josephson. The effect of polymer-surfactant interaction on the rheological properties of surfactant enhanced alkaline flooding formulations. [Phase separation, precipitation and viscosity loss]. Office of Scientific and Technical Information (OSTI), February 1993. http://dx.doi.org/10.2172/6781205.

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Malcolm Pitts, Ron Damm, and Bev Seyler. ALKALINE-SURFACTANT-POLYMER FLOODING AND RESERVOIR CHARACTERIZATION OF THE BRIDGEPORT AND CYPRESS RESERVOIRS OF THE LAWRENCE FIELD. Office of Scientific and Technical Information (OSTI), March 2003. http://dx.doi.org/10.2172/824376.

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Malcolm Pitts, Ron Damm, and Bev Seyler. ALKALINE-SURFACTANT-POLYMER FLOODING AND RESERVOIR CHARACTERIZATION OF THE BRIDGEPORT AND CYPRESS RESERVOIRS OF THE LAWRENCE FIELD. Office of Scientific and Technical Information (OSTI), March 2003. http://dx.doi.org/10.2172/824378.

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Malcolm Pitts, Ron Damm, and Bev Seyler. ALKALINE-SURFACTANT-POLYMER FLOODING AND RESERVOIR CHARACTERIZATION OF THE BRIDGEPORT AND CYPRESS RESERVOIRS OF THE LAWRENCE FIELD. Office of Scientific and Technical Information (OSTI), April 2003. http://dx.doi.org/10.2172/819498.

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