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1
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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Fathaddin, Muhammad Taufiq, Asri Nugrahanti, Putri Nurizatulshira Buang, and Khaled Abdalla Elraies. "SURFACTANT-POLYMER FLOODING PERFORMANCE IN HETEROGENEOUS TWO-LAYERED POROUS MEDIA." IIUM Engineering Journal 12, no. 1 (May 17, 2011): 31–38. http://dx.doi.org/10.31436/iiumej.v12i1.37.
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In this paper, simulation study was conducted to investigate the effect of spatial heterogeneity of multiple porosity fields on oil recovery, residual oil and microemulsion saturation. The generated porosity fields were applied into UTCHEM for simulating surfactant-polymer flooding in heterogeneous two-layered porous media. From the analysis, surfactant-polymer flooding was more sensitive than water flooding to the spatial distribution of multiple porosity fields. Residual oil saturation in upper and lower layers after water and polymer flooding was about the same with the reservoir heterogeneity. On the other hand, residual oil saturation in the two layers after surfactant-polymer flooding became more unequal as surfactant concentration increased. Surfactant-polymer flooding had higher oil recovery than water and polymer flooding within the range studied. The variation of oil recovery due to the reservoir heterogeneity was under 9.2%.
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Li, Yi Qiang, Zhe Yu Liu, Yan Yue Li, and Yi Bo Xu. "Research on the Remaining Oil Starting Mechanism in Different Pores of Polymer Surfactants Using NMR Analysis." Advanced Materials Research 1010-1012 (August 2014): 1727–34. http://dx.doi.org/10.4028/www.scientific.net/amr.1010-1012.1727.
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With its unique structure and properties, polymer surfactants have been used in chemical flooding. Compared with ordinary polymer, polymer surfactants have a higher recovery degree. However, remaining oil starting mechanism in different pores using different polymer surfactants after water flooding is still unclear. NMR (Nuclear Magnetic Resonance) has a good effect on determination of rock oil saturation and analysis of pore structure. In this paper, oil displacement experiment using kerosene which contains no hydrogen was conducted and the problem caused by the similarity between oil phase relaxation time and water relaxation time in large pores was overcome. Through the change of NMR relaxation time, oil distribution situation in different pores of ordinary polymer, refining III polymer surfactant, and Haibo III polymer surfactant after polymer flooding was measured accurately. This paper also quantitatively analyzed the contribution degree to oil recovery in pores of different sizes, and evaluated oil displacement effect of the above three kinds of oil displacement systems. The results show that when only the swept volume is considered, recovery degree of Haibo III polymer surfactant is higher, reaching 53.66%. In different systems, middle pores contribute most to recovery degree. At the same time, the remaining oil in middle pores and large pores accounts more, which is the main attack direction towards tapping the potential of remaining oil in the oilfield.
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Wu, Wen Xiang, Deng Hui Mu, and Qing Dong Liu. "Study on Physical Simulation Experiments of Different Chemical Displacement Systems." Advanced Materials Research 201-203 (February 2011): 2562–66. http://dx.doi.org/10.4028/www.scientific.net/amr.201-203.2562.
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In the reservoir condition of Liaohe oil field, the indoor physical simulation experiments of polymer / surfactant binary combination flooding and polymer / surfactant / alkali (ASP) flooding in the artificial cores have been conducted. The results show that enhanced oil recovery of polymer flooding is about 24.4%, by utilizing experiment project that polymer molecular weight is 19 million, main slug concentration is 1500mg/L. Binary flooding system that molecular weight of polymer is 19 million, main slug concentration is 1500mg/L, 0.3% surfactant YR has improved the oil recovery by 30.1%. The ASP flooding system (19 million 1500mg/L polymer +0.3% surfactant SS+ 1.2%Na2CO3) has improved the oil recovery by 28.4%. It can be seen that the binary flooding system is best.
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Zhang, Ji Hong, Yu Wang, Xi Ling Chen, Zi Wei Qu, and Dong Ke Qin. "The Effect of Following Water after Polymer Flooding on the Displacement Efficiency with Alternately Injecting Slug of Gel and Polymer/Surfactant." Advanced Materials Research 734-737 (August 2013): 1290–93. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1290.
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Aiming at the development of remaining oil after polymer flooding, the author develops an oil displacement technology, alternately injecting the slug of the gel and polymer/surfactant compound system, which can advanced improve the remained oil after polymer flooding. By using the artificial large flat-panel model, the oil displacement experiments are carried on to study the injection characteristics and the displacement efficiency of the alternately injecting the slug of gel and polymer/surfactant compound system, and whether the following water should be injected after polymer flooding has been discussed. The experimental results show that, the recovery of alternately injecting the gel and polymer/surfactant slug after polymer flooding could enhance recovery more than 10% on the basis of polymer flooding, the following water after polymer flooding has a little impact on the final recovery but increasing time and the difficulty of development. Therefore, these results provide the technology that alternately injecting the slug of the gel and polymer/surfactant could advance develop the residual oil and enhance the recovery after polymer flooding.
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He, Chen, Yu, Wen, and Liu. "Optimization Design of Injection Strategy for Surfactant-Polymer Flooding Process in Heterogeneous Reservoir under Low Oil Prices." Energies 12, no. 19 (October 7, 2019): 3789. http://dx.doi.org/10.3390/en12193789.
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Surfactant–polymer (SP) flooding has significant potential to enhance oil recovery after water flooding in mature reservoirs. However, the economic benefit of the SP flooding process is unsatisfactory under low oil prices. Thus, it is necessary to reduce the chemical costs and improve SP flooding efficiency to make SP flooding more profitable. Our goal was to maximize the incremental oil recovery of the SP flooding process after water flooding by using the equal chemical consumption cost to ensure the economic viability of the SP flooding process. Thus, a systematic study was carried out to investigate the SP flooding process under different injection strategies by conducting parallel sand pack flooding experiments to optimize the SP flooding design. Then, the comparison of the remaining oil distribution after water flooding and SP flooding under different injection strategies was studied. The results demonstrate that the EOR efficiency of the SP flooding process under the alternating injection of polymer and surfactant–polymer (PASP) is higher than that of conventional simultaneous injection of surfactant and polymer. Moreover, as the alternating cycle increases, the incremental oil recovery increases. Based on the analysis of fractional flow, incremental oil recovery, and remaining oil distribution when compared with the conventional simultaneous injection of surfactant and polymer, the alternating injection of polymer and surfactant–polymer (PASP) showed better sweep efficiency improvement and recovered more remaining oil trapped in the low permeability zone. Thus, these findings could provide insights into designing the SP flooding process under low oil prices.
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Chen, Yuqiu, Hong He, Qun Yu, Huan Liu, Lijun Chen, Xiaorui Ma, and Wenzheng Liu. "Insights into Enhanced Oil Recovery by Polymer-Viscosity Reducing Surfactant Combination Flooding in Conventional Heavy Oil Reservoir." Geofluids 2021 (May 22, 2021): 1–12. http://dx.doi.org/10.1155/2021/7110414.
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Polymer flooding has a significant potential to enhance oil recovery in a light oil reservoir. However, for polymer flooding in a conventional heavy oil reservoir, due to unfavorable mobility ratio between water and oil, the improvement of sweep efficiency is limited, resulting in a low incremental oil recovery and failure to achieve high-efficiency development for polymer flooding in a conventional heavy oil reservoir. Inspired by the EOR mechanisms of the surfactant-polymer (SP) flooding process, the polymer-viscosity reducing surfactant flooding (P-VRSF) system was proposed to enhance conventional heavy oil recovery. Thus, to gain an insight into enhancing oil recovery by P-VRSF in a conventional heavy oil reservoir, the viscosity property, oil-water interfacial tension property, and oil viscosity reduction property were investigated. A series of parallel sand pack experiments were conducted to investigate enhanced oil recovery ability of polymer flooding and P-VRSF in a heterogeneous reservoir. Then, the 2D micromodel flooding experiments were conducted to investigate the EOR mechanism from porous media to pore level. Results demonstrated that polymer could increase the viscosity of injection water and improve the sweep efficiency. The emulsifying stability of surfactant with ultralow IFT (10-3 mN/m) was worse than that of the surfactant with higher IFT (10-2 mN/m). The viscosity reduction rate of the surfactant with higher IFT was higher than 80% at different oil-water volume ratios. The incremental oi recovery of P-VRSF was higher than that of polymer flooding. Moreover, the polymer-viscosity reducing surfactant with higher IFT could have higher incremental oil recovery. The 2D micromodel flooding results showed that the swept area of polymer flooding and P-VRSF was larger than that of water flooding. Moreover, the swept area of the surfactant with good emulsifying stability was larger than that of the surfactant with ultralow IFT. These findings could provide insights into enhancing oil recovery by P-VRSF in the conventional heavy oil reservoir.
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Naukenova, A. Zh, N. D. Sarsenbekov, and B. Ye Bekbauov. "A comprehensive review of polymer and alkaline/surfactant/polymer flooding applied and researched in Kazakhstan." Bulletin of the Karaganda University. "Chemistry" series 95, no. 3 (September 30, 2019): 96–101. http://dx.doi.org/10.31489/2019ch3/96-101.
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Wang, Guo Feng, Lian Zhen Song, Zhi Li Wei, and Xue Wu Wang. "A Laboratory Study of Polymer and Surfactant Binary Combination Flooding in Reservoirs with Low to Medium Permeability." Advanced Materials Research 718-720 (July 2013): 233–38. http://dx.doi.org/10.4028/www.scientific.net/amr.718-720.233.
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Based on the viscosity of 10mPa.s after high speed shearing and the limit surfactants up to ultra-low interfacial tension, polymers and surfactant systems suitable for Longhupao oilfield were optimized by means of mixing formation simulation water with different polymers and surfactants. The relationship between the interfacial tension of the compound system and the component concentration, the effect of surfactants on viscosity, the injectivity of the compound system, etc. were studied on the basis of the research on the binary compound system. The results indicate that the viscosity of the compound system is lower than that of a single polymer solution to a certain degree and the compound system has good migration character in cores. In addition, core flooding experiments on slug combination optimization were made. The experiment results show that the compounded system with pre-pad polymers and surfactants has good oil displacement efficiency and in terms of enhancing the recovery efficiency, chemical flooding should be implemented as soon as possible.
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Jin, Baoguang, Hanqiao Jiang, Xiansong Zhang, Jing Wang, Jing Yang, and Wei Zheng. "Numerical Simulation of Surfactant-Polymer Flooding." Chemistry and Technology of Fuels and Oils 50, no. 1 (March 2014): 55–70. http://dx.doi.org/10.1007/s10553-014-0490-8.
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Yuan, Fu Qing, and Zhen Quan Li. "An Easy Calculation Method on Sweep Efficiency of Chemical Flooding." Applied Mechanics and Materials 275-277 (January 2013): 496–501. http://dx.doi.org/10.4028/www.scientific.net/amm.275-277.496.
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According to the geological parameters of Shengli Oilfield, sweep efficiency of chemical flooding was analyzed according to injection volume, injection-production parameters of polymer flooding or surfactant-polymer compound flooding. The orthogonal design method was employed to select the important factors influencing on expanding sweep efficiency by chemical flooding. Numerical simulation method was utilized to analyze oil recovery and sweep efficiency of different flooding methods, such as water flooding, polymer flooding and surfactant-polymer compound flooding. Finally, two easy calculation models were established to calculate the expanding degree of sweep efficiency by polymer flooding or SP compound flooding than water flooding. The models were presented as the relationships between geological parameters, such as effective thickness, oil viscosity, porosity and permeability, and fluid parameters, such as polymer-solution viscosity and oil-water interfacial tension. The precision of the two models was high enough to predict sweep efficiency of polymer flooding or SP compound flooding.
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Stoll, W. M., H. al Shureqi, J. Finol, S. A. Al-Harthy, S. Oyemade, A. de Kruijf, J. van Wunnik, F. Arkesteijn, R. Bouwmeester, and M. J. Faber. "Alkaline/Surfactant/Polymer Flood: From the Laboratory to the Field." SPE Reservoir Evaluation & Engineering 14, no. 06 (December 19, 2011): 702–12. http://dx.doi.org/10.2118/129164-pa.
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Summary After two decades of relative calm, chemical enhanced-oil-recovery (EOR) technologies are currently revitalized globally. Techniques such as alkaline/surfactant/polymer (ASP) flooding, originally developed by Shell, have the potential to recover significant fractions of remaining oil at a CO2 footprint that is low compared with, for example, thermal EOR, and they do not depend on a valuable miscible agent such as hydrocarbon gas. On the other hand, chemical EOR technologies typically require large quantities of chemical products such as surfactants and polymers, which must be transported to, and handled safely in, the field. Despite rising industry interest in chemical EOR, until today only polymer flooding has been applied on a significant scale, whereas applications of surfactant/polymer or alkaline ASP flooding were limited to multiwell pilots or to small field scale. Next to the oil-price fluctuations of the past two decades, technical reasons that discouraged the application of chemical EOR are excessive formation of carbonate or silica scale and formation of strong emulsions in the production facilities. Having identified significant target-oil volumes for ASP flooding, Petroleum Development Oman (PDO), supported by Shell Technology Oman, carried out a sequence of single-well pilots in three fields, sandstone and carbonate, to assess the flooding potential of tailor-made chemical formulations under real subsurface conditions, and to quantify the benefits of full-field ASP developments. This paper discusses the extensive design process that was followed. Starting from a description of the optimization of chemical phase behavior in test-tube and coreflood experiments, we elaborate how the key chemical and flow properties of an ASP flood are captured to calibrate a comprehensive reservoir-simulation model. Using this model, we evaluate PDO's single-well pilots and demonstrate how these results are used to design a pattern- flood pilot.
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Turnaeva, E. A., E. A. Sidorovskaya, D. S. Adakhovskij, E. V. Kikireva, N. Yu Tret'yakov, I. N. Koltsov, S. S. Volkova, and A. A. Groman. "Oil emulsion characteristics as significance in efficiency forecast of oil-displacing formulations based on surfactants." Oil and Gas Studies, no. 3 (July 15, 2021): 91–107. http://dx.doi.org/10.31660/0445-0108-2021-3-91-107.
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Enhanced oil recovery in mature fields can be implemented using chemical flooding with the addition of surfactants using surfactant-polymer (SP) or alkaline-surfactant-polymer (ASP) flooding. Chemical flooding design is implemented taking into account reservoir conditions and composition of reservoir fluids. The surfactant in the oil-displacing formulation allows changing the rock wettability, reducing the interfacial tension, increasing the capillary number, and forming an oil emulsion, which provides a significant increase in the efficiency of oil displacement. The article is devoted with a comprehensive study of the formed emulsion phase as a stage of laboratory selection of surfactant for SP or ASP composition. In this work, the influence of aqueous phase salinity level and the surfactant concentration in the displacing solution on the characteristics of the resulting emulsion was studied. It was shown that, according to the characteristics of the emulsion, it is possible to determine the area of optimal salinity and the range of surfactant concentrations that provide increased oil displacement. The data received show the possibility of predicting the area of effectiveness of ASP and SP formulations based on the characteristics of the resulting emulsion.
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Taiwo, Oluwaseun, Kelani Bello, Ismaila Mohammed, and Olalekan Olafuyi. "Characterization of Surfactant Flooding for Light Oil Using Gum Arabic." International Journal of Engineering Research in Africa 21 (December 2015): 136–47. http://dx.doi.org/10.4028/www.scientific.net/jera.21.136.
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Surfactant flooding, a chemical IOR technique is one of the viable EOR processes for recovering additional oil after water flooding. This is because it reduces the interfacial tension between the oil and water and allows trapped oil to be released for mobilization by a polymer.In this research, two sets of experiments were performed. First, the optimum surfactant concentration was determined through surfactant polymer flooding using a range of surfactant concentration of 0.1% to 0.6% and 15% of polymer. Secondly, another set of experiments to determine the optimum flow rate for surfactant flooding was carried out using the optimum surfactant concentration obtained. Lauryl Sulphate (Sodium Dodecyl Sulphate, SDS), an anionic surfactant, was used to alter the interfacial tension and reduce capillary pressure while Gum Arabic, an organic adhesive gotten from the hardened sap of the Acacia Senegal and Acacia Seyal trees, having a similar molecular structure and chemical characteristics with Xanthan Gum, was the polymer used to mobilize the oil.The results show that above 0.5%, oil recovery decreases with increase in concentration such that between 0.5 and 0.6%, a decrease of (20% -19%) is recorded. This suggests that it would be uneconomical to exceed surfactant concentration of 0.5%. It is shown in the result of the first set of experiments that a range of oil recovery of 59% to 76% for water flooding and a range of 11.64% to 20.02% additional oil recovery for surfactant Polymer flooding for a range of surfactant flow rate of surfactant concentration of 0.1% to 0.6%. For the second sets of experiments, a range of oil recovery of 64% to 68% for water flooding and a range of 15% to 24% additional oil recovery for surfactant flooding for a range of surfactant flow rate of surfactant flow rate of 1cc/min to 6cc/min. The Optimum surfactant flow rate resulting in the highest oil recovery for the chosen core size is 3cc/min. It's highly encouraged that the critical displacement rate is maintained to prevent the development of slug fingers.In summary, an optimum Surfactant flow rate is required for better performance of a Surfactant flooding.
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Shakeel, Mariam, Aida Samanova, Peyman Pourafshary, and Muhammad Rehan Hashmet. "Capillary Desaturation Tendency of Hybrid Engineered Water-Based Chemical Enhanced Oil Recovery Methods." Energies 14, no. 14 (July 20, 2021): 4368. http://dx.doi.org/10.3390/en14144368.
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Several studies have shown the synergetic benefits of combining various chemical enhanced oil recovery (CEOR) methods with engineered waterflooding (EWF) in both sandstones and carbonate formations. This paper compares the capillary desaturation tendency of various hybrid combinations of engineered water (EW) and CEOR methods with their conventional counterparts. Several coreflood experiments were conducted, including EW-surfactant flooding (EWSF), EW-polymer flooding (EWPF), EW-alkali-surfactant flooding (EWASF), EW-surfactant-polymer flooding (EWSPF), and EW-alkali-surfactant-polymer flooding (EWASP). Capillary numbers (Nc) and corresponding residual oil saturation (Sor) for each scenario are compared with capillary desaturation curves (CDC) of conventional CEOR methods from the literature. The results indicate that hybrid EW–CEOR methods have higher capillary desaturation tendency compared to conventional methods. The capillary numbers obtained by standalone polymer flooding (PF) are usually in the range from 10−6 to 10−5, which are not sufficient to cause a significant reduction in Sor. However, the hybrid EW-polymer flooding approach considerably reduced the Sor for the same Nc values, proving the effectiveness of the investigated method. The hybrid EWASP flooding caused the highest reduction in Sor (23%) against Nc values of 8 × 10−2, while conventional ASP flooding reduced the Sor for relatively higher Nc values (3 × 10−3 to 8 × 10−1). Overall, the hybrid methods are 30–70% more efficient in terms of recovering residual oil, compared to standalone EWF and CEOR methods. This can be attributed to the combination of different mechanisms such as wettability modification by EW, ultralow interfacial tension by alkali and surfactant, reduced surfactant adsorption by alkali addition, and favorable mobility ratio by polymer. Based on the promising results, these hybrid techniques can be effectively implemented to carbonate formations with harsh reservoir conditions such as high salinity and high temperature.
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Yan, Limin, Zhenggang Cui, Binglei Song, Xiaomei Pei, and Jianzhong Jiang. "Dioctyl Glyceryl Ether Ethoxylates as Surfactants for Surfactant–Polymer Flooding." Energy & Fuels 30, no. 7 (June 30, 2016): 5425–31. http://dx.doi.org/10.1021/acs.energyfuels.6b00472.
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Zhang, Rong Jun, Xiao Ke Wang, Jin Lin Zhao, Zheng Peng Zhou, and Gang Chen. "Evaluation of a Composite Flooding Formula Used to Enhance the Oil Recovery of Ansai Oil Field." Materials Science Forum 984 (April 2020): 183–88. http://dx.doi.org/10.4028/www.scientific.net/msf.984.183.
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The composite flooding formula utilizes the characteristics of polymer flooding and surfactant flooding to compensate for the shortage of single component chemical flooding, reduce the oil-water interfacial tension to a certain extent, and broaden the maintenance range of low interfacial tension. The combined effects and synergies in the oil displacement process enhance oil recovery and allow it to adapt to a wider range of reservoir conditions. In this paper, the high surface active polymer-surfactant flooding formula suitable for the Chang 6 reservoir in Ansai Oilfield was evaluated. The general technical index of the viscoelastic surfactant fracturing fluid and the composite flooding surfactant were evaluated. The technical requirements are evaluation criteria, and comprehensive evaluation is made from several aspects such as salt tolerance, interfacial tension and emulsifying properties.
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Al Kalbani, M. M., M. M. Jordan, E. J. Mackay, K. S. Sorbie, and L. Nghiem. "Barium Sulfate Scaling and Control during Polymer, Surfactant, and Surfactant/Polymer Flooding." SPE Production & Operations 35, no. 01 (February 1, 2020): 068–84. http://dx.doi.org/10.2118/193575-pa.
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Liu, Yang, Jian Zhang, Xingcai Wu, Xiaodong Kang, Baoshan Guan, Xianjie Li, Yinzhu Ye, Peiwen Xiao, Xiaocong Wang, and Shichao Li. "Experimental Investigation on a Novel Particle Polymer for Enhanced Oil Recovery in High Temperature and High Salinity Reservoirs." Journal of Chemistry 2021 (April 22, 2021): 1–8. http://dx.doi.org/10.1155/2021/5593038.
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Conventional polymer flooding include polymer flooding, surfactant-polymer flooding (SP), alkaline-surfactant-polymer flooding (ASP), and crosslinked polymer gel flooding. However, these technologies in oilfield, especially in high temperature and high salinity, are limited due to the poor ability of temperature and salinity resistance of polymer. In this work, a novel polymer particle (soft microgel, SMG) is used as the research object under the reservoir condition of high salinity (20 × 104 mg/L) to evaluate the physical and chemical properties of submillimeter-scale SMG and the effect of profile control and oil displacement. The investigation of the physical and chemical properties of submillimeter-scale SMG shows that it has the characteristics of low viscosity, easy injection, good plugging property, swelling property, rheological property, and excellent thermal stability. After 6 months of high temperature and high salinity aging, there is no hydration and hydrolysis of submillimeter-scale SMG as the traditional polymers under high temperature and high salinity. The parallel two-core flooding experiments indicate that the submillimeter-scale SMG has a better effect of profile control and oil displacement, which increases the fraction flow rate( f w ) of low-permeability core from 5.12% before SMG-flooding to 85.29% and the total increase of recovery as high as 14.07%. The comprehensive analysis demonstrates that the submillimeter-scale SMG has the potential to solve the problem that the polymer flooding cannot be applied to the high temperature and high salinity reservoir, and it is also expected to improve the uneven waterflooding in the reservoir.
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Sun, Chen, Hu Guo, Yiqiang Li, and Kaoping Song. "Recent Advances of Surfactant-Polymer (SP) Flooding Enhanced Oil Recovery Field Tests in China." Geofluids 2020 (May 26, 2020): 1–16. http://dx.doi.org/10.1155/2020/8286706.
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Recently, there are increasing interests in chemical enhanced oil recovery (EOR) especially surfactant-polymer (SP) flooding. Although alkali-surfactant-polymer (ASP) flooding can make an incremental oil recovery factor (IORF) of 18% original oil in place (OOIP) according to large-scale field tests in Daqing, the complex antiscaling and emulsion breaking technology as well as potential environment influence makes some people turn to alkali-free SP flooding. With the benefit of high IORF in laboratory and no scaling issue to worry, SP flooding is theoretically better than ASP flooding when high quality surfactant is available. Many SP flooding field tests have been conducted in China, where the largest chemical flooding application is reported. 10 typical large-scale SP flooding field tests were critically reviewed to help understand the benefit and challenge of SP flooding in low oil price era. Among these 10 field tests, only one is conducted in Daqing Oilfield, although ASP flooding has entered the commercial application stage since 2014. 2 SP tests are conducted in Shengli Oilfield. Both technical and economic parameters are used to evaluate these tests. 2 of these ten tests are very successful; the others were either technically or economically unsuccessful. Although laboratory tests showed that SP flooding can attain IORF of more than 15%, the average predicted IORF for these 10 field tests was 12% OOIP. Only two SP flooding tests in (SP 1 in Liaohe and SP 7 in Shengli) were reported actual IORF higher than 15% OOIP. The field test in Shengli was so successful that many enlarged field tests and industrial applications were carried out, which finally lead to a commercial application of SP flooding in 2008. However, other SP projects are not documented except two (SP7 and SP8). SP flooding tests in low permeability reservoirs were not successful due to high surfactant adsorption. It seems that SP flooding is not cost competitive as polymer flooding and ASP flooding if judged by utility factor (UF) and EOR cost. Even the most technically and economically successful SP1 has a much higher cost than polymer flooding and ASP flooding, SP flooding is thus not cost competitive as previously expected. The cost of SP flooding can be as high as ASP flooding, which indicates the importance of alkali. How to reduce surfactant adsorption in SP flooding is very important to cost reduction. It is high time to reevaluate the potential and suitable reservoir conditions for SP flooding. The necessity of surfactant to get ultra-low interfacial tension for EOR remains further investigation. This paper provides the petroleum industry with hard-to-get valuable information.
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Tang, Shan Fa, Xiao Dong Hu, Xiang Nan Ouyang, Shuang Xi Yan, Shou Cheng Wen, and Yan Ling Lai. "Experimental Study of Anionic Gemini Surfactant Enhancing Waterflooding Recovery Ratio." Advanced Materials Research 361-363 (October 2011): 469–72. http://dx.doi.org/10.4028/www.scientific.net/amr.361-363.469.
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The oil-water interfacial tension measurement and enhancing water displacement recovery experiment were carried out, and the effects of various parameters such as category of surfactants, anionic Gemini surfactant concentration, water medium salinity, core permeability, polymer and non-ionic surfactant on anionic Gemini surfactants enhancing water displacement recovery were investigated in detail. The results show that surfactants category is different, its enhancing water flooding recovery efficiency is different, and effect of enhanced oil recovery is consistent with surfactant ability to reduce oil-water interfacial tension. The anionic Gemini surfactant AN12-4-12 is the best in enhancing water flooding recovery efficiency, because it can reduce the oil-water interfacial tension to 5×10-3 mN•m-1. Increasing the concentration of AN12-4-12 is favorable to enhance water displacement recovery. Such as when injecting 0.5PV solution containing 800mg•L-1 AN12-4-12, enhancing water displacement recovery is 11.67%. AN12-4-12 has good adaptability to different salinities (5~25×104 mg•L-1) and low permeability reservoir in improving water displacement recovery. Adding non-ionic surfactant ANT into AN12-4-12 solution can further reduce oil-water interfacial tension and enhance water flooding recovery efficiency. For example, injecting 0.5PV surfactant solution containing 400mg•L-1 AN12-4-12 and 100mg•L-1 can enhance water displacement recovery of 10.7%.
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Rai, Khyati, Russell T. Johns, Mojdeh Delshad, Larry W. Lake, and Ali Goudarzi. "Oil-recovery predictions for surfactant polymer flooding." Journal of Petroleum Science and Engineering 112 (December 2013): 341–50. http://dx.doi.org/10.1016/j.petrol.2013.11.028.
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Liu, Yang, and Jiu Hong Feng. "The Evaluation Experiment Research on Sp Binary Composite System Performance and the Oil Displacement Effect." Advanced Materials Research 807-809 (September 2013): 2534–43. http://dx.doi.org/10.4028/www.scientific.net/amr.807-809.2534.
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SP binary composite system can reduce the interfacial tension, has good viscoelasticity, and has similar displacement effect with ASP ternary composite system. In addition, the scaling formation can be weaken because it does not contain alkali. Therefore, it plays a important role in guiding the formulas of SP binary composite system and designing the injection scheme to evaluate the main performance and oil displacement effect of SP binary composite system. Experiments on the main performance evaluation, microscopic simulation model for oil displacement and oil displacement in cores have been carried in this paper, which is intended for the new type of surfactant (HLX-BO1 type)/polymer binary complex system which is applied in SP binary composite flooding test block of Daqing oil field. The emulsification property, adsorption characteristics, stability and rheological property of the SP binary composite system have been evaluated. The oil displacement effect of polymer flooding, surfactant flooding, and SP binary composite flooding have been analyzed in this paper. The evaluation experimental research on SP binary complex system performance shows that: 1The binary composite system has good viscosity stability and interfacial tension stability. 2the emulsification time and emulsification degree both increase With the increasing of surfactant concentration. 3The higher oil content in the oil sand, the greater the surfactant adsorption capacity. 4The concentration of surfactant has less affect on the apparent viscosity of the polymer solution, while alkali has greater influence on the apparent viscosity of the polymer solution. The oil displacement experimental research on SP binary system shows that the oil displacement effect of SP binary system is significantly better than that of the unitary system of polymer or surfactant alone. The oil displacement effect is well whether SP system is flooded after water flooding or polymer flooding. The average enhanced oil recovery rates of artificial cores in the oil displacement experiment are 17.5% and 10.10% respectively. The average enhanced oil recovery rate of natural cores in the oil displacement experiment after polymer flooding is 9.5%.
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Li, Jierui, Weidong Liu, Linghui Sun, Sunan Cong, Ruixuan Jia, Junjie Zhang, and Ye Yang. "Effect of Emulsification on Surfactant Partitioning in Surfactant‐Polymer Flooding." Journal of Surfactants and Detergents 22, no. 6 (September 11, 2019): 1387–94. http://dx.doi.org/10.1002/jsde.12353.
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Flaaten, Adam K., Quoc P. Nguyen, Jieyuan Zhang, Hourshad Mohammadi, and Gary A. Pope. "Alkaline/Surfactant/Polymer Chemical Flooding Without the Need for Soft Water." SPE Journal 15, no. 01 (October 14, 2009): 184–96. http://dx.doi.org/10.2118/116754-pa.
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Summary Alkaline/surfactant/polymer (ASP) flooding using conventional alkali requires soft water. However, soft water is not always available, and softening hard brines may be very costly or infeasible in many cases depending on the location, the brine composition, and other factors. For instance, conventional ASP uses sodium carbonate to reduce the adsorption of the surfactant and generate soap in-situ by reacting with acidic crude oils; however, calcium carbonate precipitates unless the brine is soft. A form of borax known as metaborate has been found to sequester divalent cations such as Ca++ and prevent precipitation. This approach has been combined with the screening and selection of surfactant formulations that will perform well with brines having high salinity and hardness. We demonstrate this approach by combining high-performance, low-cost surfactants with cosurfactants that tolerate high salinity and hardness and with metaborate that can tolerate hardness as well. Chemical formulations containing surfactants and alkali in hard brine were screened for performance and tolerance using microemulsion phase-behavior experiments and crude at reservoir temperature. A formulation was found that, with an optimum salinity of 120,000 ppm total dissolved solids (TDS), 6,600 ppm divalent cations, performed well in corefloods with high oil recovery and almost zero final chemical flood residual oil saturation. Additionally, chemical formulations containing sodium metaborate and hard brine gave nearly 100% oil recovery with no indication of precipitate formation. Metaborate chemistry was incorporated into a mechanistic, compositional chemical flooding simulator, and the simulator was then used to model the corefloods. Overall, novel ASP with metaborate performed comparably to conventional ASP using sodium carbonate in soft water, demonstrating advancements in ASP adaptation to hard, saline reservoirs without the need for soft brine, which increases the number of oil reservoirs that are candidates for enhanced oil recovery using ASP flooding.
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Wang, Ke Liang, Guang Pu Jiao, Han Feng, and Tian Tian Fu. "Experiment Research of Flooding Efficiency on Alternative Injection of Low-Tension System and Foam System." Advanced Materials Research 524-527 (May 2012): 1389–94. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1389.
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To make binary low-tension system play a vital role in improving oil displacement efficiency and foam system expand swept volume, binary low-tension system alternates with binary foam system flooding laboratory research is carried out after the polymer flooding technology. The method of airflow is used to proceed with foaming performance experiments by nitrogen gas. Surfactant CYL which foaming performance is stronger has good compatibility with alkali-free surfactant. The evaluation of the interfacial tension experiments shows that surfactant HLX has a low interfacial tension; the HLX's ability of reducing interfacial tension is less affected by CYL. It is shown through experiment that displacement recovery of binary foam system is 7.84% and binary low-tension system is 5.87% after polymer flooding, as well as the injection pattern of (0.05PV binary foam system+0.05PV N2+0.1PV binary low-tension system) alternating three times is best, which displacement recovery is 14.22% and 12.26% in natural core after polymer flooding. The injection pattern of profile control and oil displacement can attain a perfect effect after polymer flooding.
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Wang, Ke-Liang, Lei-Lei Zhang, Xue Li, and Yang-Yang Ming. "Experimental Study on the Properties and Displacement Effects of Polymer Surfactant Solution." Journal of Chemistry 2013 (2013): 1–6. http://dx.doi.org/10.1155/2013/956027.
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Based on the characteristics of oil reservoirs and the requirements of further enhancing oil recovery at high water cut stage of Pubei Oilfield, the displacement performance of polymer surfactant is evaluated. Reasonable injection parameters and oil displacement effects after water flooding are also researched. Compared with conventional polymer with intermediate molecular weight, polymer surfactant has the properties of higher viscosity at low concentration condition and lower interfacial tension. Laboratory experiments indicate that the displacement effect of polymer surfactant is much better than that of conventional polymer at a slug size of 0.57 PV. The oil recovery of polymer surfactant increases by more than 10% after water flooding. Considering the actual situation of low-permeability of Pubei Oilfield reservoirs, the system viscosity of 30 mPa·s is chosen. The corresponding concentration of Type III polymer surfactant is 600 mg/L and the injected slug is 0.57 PV and the oil recovery can be increased by 11.69%.
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Lv, Peng, Ming Yuan Li, and Mei Qin Lin. "Optimization of Surfactant and Polymer for SP Flooding of Zahra Oil." Applied Mechanics and Materials 535 (February 2014): 701–4. http://dx.doi.org/10.4028/www.scientific.net/amm.535.701.
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Producing ultra-low interfacial tensions and maintaining high viscosity is the most important mechanism relating to SP flooding for enhanced oil recovery. The interfacial tension between surfactant (PJZ-2 and BE)/polymer solution and Zahra oil was evaluated in the work. Based on the evaluatiojn of interfacial tension, the polymer FP6040s/surfactant BE system was selected as the SP flooding system for Zahra oil field.
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Guo, Yaohao, Lei Zhang, Guangpu Zhu, Jun Yao, Hai Sun, Wenhui Song, Yongfei Yang, and Jianlin Zhao. "A Pore-Scale Investigation of Residual Oil Distributions and Enhanced Oil Recovery Methods." Energies 12, no. 19 (September 29, 2019): 3732. http://dx.doi.org/10.3390/en12193732.
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Water flooding is an economic method commonly used in secondary recovery, but a large quantity of crude oil is still trapped in reservoirs after water flooding. A deep understanding of the distribution of residual oil is essential for the subsequent development of water flooding. In this study, a pore-scale model is developed to study the formation process and distribution characteristics of residual oil. The Navier–Stokes equation coupled with a phase field method is employed to describe the flooding process and track the interface of fluids. The results show a significant difference in residual oil distribution at different wetting conditions. The difference is also reflected in the oil recovery and water cut curves. Much more oil is displaced in water-wet porous media than oil-wet porous media after water breakthrough. Furthermore, enhanced oil recovery (EOR) mechanisms of both surfactant and polymer flooding are studied, and the effect of operation times for different EOR methods are analyzed. The surfactant flooding not only improves oil displacement efficiency, but also increases microscale sweep efficiency by reducing the entry pressure of micropores. Polymer weakens the effect of capillary force by increasing the viscous force, which leads to an improvement in sweep efficiency. The injection time of the surfactant has an important impact on the field development due to the formation of predominant pathway, but the EOR effect of polymer flooding does not have a similar correlation with the operation times. Results from this study can provide theoretical guidance for the appropriate design of EOR methods such as the application of surfactant and polymer flooding.
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Han, Choongyong, Mojdeh Delshad, Kamy Sepehrnoori, and Gary Arnold Pope. "A Fully Implicit, Parallel, Compositional Chemical Flooding Simulator." SPE Journal 12, no. 03 (September 1, 2007): 322–38. http://dx.doi.org/10.2118/97217-pa.
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Summary A fully implicit, parallel, compositional reservoir simulator has been developed that includes both a cubic equation of state model for the hydrocarbon phase behavior and Hand's rule for the surfactant/oil/brine phase behavior. The aqueous species in the chemical model include surfactant, polymer, and salt. The physical property models include surfactant/oil/brine phase behavior, interfacial tension, viscosity, adsorption, and relative permeability as a function of trapping number. The fully implicit simulation results were validated by comparison with results from our IMPEC chemical flooding simulator (UTCHEM). The results indicate that the simulator scales well using clusters of workstations. Also, simulation results from parallel runs are identical to those using a single processor. Field-scale surfactant/polymer flood simulations were successfully performed with over 1,000,000 gridblocks using multiple processors. Introduction Chemical flooding is a method to improve oil recovery that involves the injection of a solution of surfactant and polymer followed by a polymer solution. The surfactant causes the mobilization of oil by decreasing interfacial tension, whereas the polymer increases the sweep efficiency by lowering the mobility ratio. Chemical flooding has the potential to recover a very high fraction of the remaining oil in a reservoir, but the process needs to be designed to be both cost effective and robust, which requires careful optimization. Several reservoir simulators with chemical flooding features have been developed as a tool for optimizing the design (Delshad et al. 1996; Schlumberger 2004; Computer Modeling 2004). The University of Texas chemical flooding simulator, UTCHEM (Delshad et al. 1996) is an example of a simulator that has been used for this purpose. However, because UTCHEM is an Implicit Pressure and Explicit Concentration (IMPEC) formulation and in its current form cannot run on parallel computers, realistic surfactant/polymer flooding simulations are limited to around 100,000 gridblocks because of small timestep restrictions and insufficient memory. Recently, the appropriate chemical module was added to the fully implicit, parallel, EOS compositional simulator called GPAS (General Purpose Adaptive Simulator) based on a hybrid approach (John et al. 2005). GPAS uses a cubic equation of state model for the hydrocarbon phase behavior and the parallel and object-based Fortran 95 framework for managing memory, input/output, and the necessary communication between processors (Wang et al. 1999; Parashar et al. 1997). In the hybrid approach implemented in GPAS, the material balance equations for hydrocarbon and water components are solved implicitly first. Then, the material balance equations for the aqueous components such as surfactant, polymer, and electrolytes are solved explicitly using the updated phase fluxes, saturations, and densities.
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Riswati, Shabrina Sri, Wisup Bae, Changhyup Park, Asep K. Permadi, and Adi Novriansyah. "Nonionic Surfactant to Enhance the Performances of Alkaline–Surfactant–Polymer Flooding with a Low Salinity Constraint." Applied Sciences 10, no. 11 (May 28, 2020): 3752. http://dx.doi.org/10.3390/app10113752.
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This paper presents a nonionic surfactant in the anionic surfactant pair (ternary mixture) that influences the hydrophobicity of the alkaline–surfactant–polymer (ASP) slug within low-salinity formation water, an environment that constrains optimal designs of the salinity gradient and phase types. The hydrophobicity effectively reduced the optimum salinity, but achieving as much by mixing various surfactants has been challenging. We conducted a phase behavior test and a coreflooding test, and the results prove the effectiveness of the nonionic surfactant in enlarging the chemical applicability by making ASP flooding more hydrophobic. The proposed ASP mixture consisted of 0.2 wt% sodium carbonate, 0.25 wt% anionic surfactant pair, and 0.2 wt% nonionic surfactant, and 0.15 wt% hydrolyzed polyacrylamide. The nonionic surfactant decreased the optimum salinity to 1.1 wt% NaCl compared to the 1.7 wt% NaCl of the reference case with heavy alcohol present instead of the nonionic surfactant. The coreflooding test confirmed the field applicability of the nonionic surfactant by recovering more oil, with the proposed scheme producing up to 74% of residual oil after extensive waterflooding compared to 51% of cumulative oil recovery with the reference case. The nonionic surfactant led to a Winsor type III microemulsion with a 0.85 pore volume while the reference case had a 0.50 pore volume. The nonionic surfactant made ASP flooding more hydrophobic, maintained a separate phase of the surfactant between the oil and aqueous phases to achieve ultra-low interfacial tension, and recovered the oil effectively.
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Skripkin, A. G., I. N. Koltsov, and S. V. Milchakov. "Experimental studies of the capillary desaturation curve in polymer-surfactant flooding." PROneft’. Proffessional’no o nefti 6, no. 1 (March 31, 2021): 40–46. http://dx.doi.org/10.51890/2587-7399-2021-6-1-40-46.
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The paper presents the results of laboratory studies of polymer-surfactant flooding on core samples of different permeability. The obtained data are used in hydrodynamic modeling.
Experimental studies included:
• study of the dynamics of oil displacement, plotting the dependence of the residual oil saturation on the surfactant concentration – interfacial tension at the interface of the surfactant-oil solution;
• comparative experimental studies of residual oil saturation when oil is displaced by surfactant compositions of various manufacturers;
• comparative studies of phase permeability in flood experiments for the filtration of oil and water, oil and polymer-surfactant solution at different ratios in the flow.
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Feng, Ru-Sen, Yong-Jun Guo, Xin-Min Zhang, Jun Hu, and Hua-Bing Li. "Alkali/Surfactant/Polymer Flooding in the Daqing Oilfield Class II Reservoirs Using Associating Polymer." Journal of Chemistry 2013 (2013): 1–6. http://dx.doi.org/10.1155/2013/275943.
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Hydrophobically modified associating polyacrylamide (HAPAM) has good compatibility with the Daqing heavy alkylbenzene sulfonate surfactant. The HAPAM alkali/surfactant/polymer (ASP) system can generate ultralow interfacial tension in a wide range of alkali/surfactant concentrations and maintain stable viscosity and interfacial tension for 120 days. The HAPAM ASP system has good injectivity for the Daqing class II reservoirs (100–300 × 10−3 μm2) and can improve oil recovery by more than 25% on top of water flooding. In the presence of both the alkali and the surfactant, the surfactant interacts with the associating groups of the polymer to form more micelles, which can significantly enhance the viscosity of the ASP system. Compared with using HPAM (Mw = 2.5 MDa), using HAPAM can reduce the polymer use by more than 40%.
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Xiao, Han Min, Ling Hui Sun, and Hui Hui Kou. "Mass Transfer Mechanisms of ASP Flooding in Porous Media." Advanced Materials Research 550-553 (July 2012): 2738–44. http://dx.doi.org/10.4028/www.scientific.net/amr.550-553.2738.
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Experiments on chromatography separation are taken for ASP flooding. Mass transfer equation is estabilished and mutiple adsorption factor is obtained. Mutiple adsorption factor is used to analyze the experiment results. The Mass transfer property of alkali, surfactant and polymer during single fooding and ASP flooding and the effect on interfacial tension of oil/solution are discussed. The results show the diffrence of hesteris degree of alkali, surfactant and polymer deduce the chromatography separation, lowing the active of ASP flooding. Accoding to interfacial tension, the efficent length of ASP slug is discussed.
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Xuan, Yinglong, Desheng Ma, Minghui Zhou, and Ming Gao. "Significance of polymer on emulsion stability in surfactant-polymer flooding." Journal of Applied Polymer Science 132, no. 26 (March 26, 2015): n/a. http://dx.doi.org/10.1002/app.42171.
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Yin, Dandan, and Dongfeng Zhao. "Main Controlling Factor of Polymer-Surfactant Flooding to Improve Recovery in Heterogeneous Reservoir." Advances in Materials Science and Engineering 2017 (2017): 1–8. http://dx.doi.org/10.1155/2017/5247305.
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This study aims to analyze the influence of viscosity and interfacial tension (IFT) on the recovery in heterogeneous reservoir and determines the main controlling factors of the polymer-surfactant (SP) flooding. The influence of the salinity and shearing action on the polymer viscosity and effects of the surfactant concentration on the IFT and emulsion behavior between chemical agent and oil were studied through the static and flooding experiments. The results show that increasing the concentration of polymer GF-11 (HPAM) can reduce the influence of the salinity and GF-11 has high shear-resistance property. In the condition of the Jilin Oilfield, the oil/water IFT can reach 10−3 mN/m when the surfactant concentration is 0.3 wt%. The lower the IFT is, the easier the emulsion of SP and oil is formed. Seven flooding experiments are conducted with the SP system. The results show that the recovery can be improved for 5.02%–15.98% under the synergistic effect of the polymer and surfactant. In the heterogeneous reservoir, the contribution of oil recovery is less than that of the sweep volume.
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Wu, Wen Xiang, and Zhong Qi Yu. "Research on Oil-Water Interfacial Properties Effect of Polymer / Surfactant Binary Flooding System." Advanced Materials Research 201-203 (February 2011): 2558–61. http://dx.doi.org/10.4028/www.scientific.net/amr.201-203.2558.
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The formula of surfactant(QY-3、SHSA-HN6、SS) and polymer compound system, and the interfacial characteristics between oil and water of Henan oil field were evaluated, the binary composite system formula adapt to the field was explored. The results show that the binary composite system (surfactant QY-3 and polymer 1630S) and oil-water in Henan can achieve ultra-low interfacial tension(＜10-3mN/m); If the addition agent NaCl was added to the composite system (Surfactant Ss and polymer ZL-Ⅱ or Surfactant Ss and polymer KYPAM) that the interfacial tension between oil and water can be reduced effectively.
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Haq, Bashirul, Jishan Liu, and Keyu Liu. "Green enhanced oil recovery (GEOR)." APPEA Journal 57, no. 1 (2017): 150. http://dx.doi.org/10.1071/aj16116.
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Green enhanced oil recovery (GEOR) is a chemical enhanced oil recovery (EOR) method involving the injection of specific green chemicals (surfactants/alcohols/polymers) that effectively displace oil because of their phase-behaviour properties, which decrease the interfacial tension (IFT) between the displacing liquid and the oil. In this process, the primary displacing liquid slug is a complex chemical system called a micellar solution, containing green surfactants, co-surfactants, oil, electrolytes and water. The surfactant slug is relatively small, typically 10% pore volume (PV). It may be followed by a mobility buffer such as polymer. The total volume of the polymer solution is typically ~1 PV. This study was conducted to examine the effectiveness of the combination of microbial by-products Bacillus subtilise strain JF-2 bio-surfactant and alcohol in recovering residual oil. It also considered whether bio-surfactant capability could be improved by blending it with non-ionic green surfactant. The study consisted of a phase behaviour study, IFT measurement and core-flooding experiments. In the phase behaviour study, it was found that 0.5% alkyl polyglycosides (APG) and 0.5–1.00% of butanol at 2% NaCl gave stable middle phase micro-emulsion. Non-ionic (APG 264) and anionic (bio-surfactant) mixtures are able to form stable middle phase micro-emulsion. Based on IFT reduction, two low concentrations (40 and 60 mg/l) of JF-2 bio-surfactant were identified where IFT values were low. The bio-surfactant and butanol formulation produced a total ~39.3% of oil initially in place (OIIP).
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Cui, Wei Lin, Wu Ju Xu, and Ling Jian Song. "The Influence of Different Kinds of Surfactants on Rheology in Polymer/Surfactant Complex Flooding." Applied Mechanics and Materials 437 (October 2013): 1089–92. http://dx.doi.org/10.4028/www.scientific.net/amm.437.1089.
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Because of alkaline declining the sweep efficiency, causing scale formation problem in the reservoir and the well bottom and the tubular pipes, so polymer/surfactant compound flooding technology is the emphasis in the research of enhanced recovery. So the articles study the regulation of different kinds of surface active agents at different temperature by MARS Rheometer. The testing result showed that the variation of viscocity under the interaction between the surface active agent and association polymer according to “three stage” model .The linear viscoelastic region of stress decrease when different surface active agents are put into polymer liquor, and the higher frequency, the better elasticity of polymer liquor. The hydrophobic association between the surface active agents and polymer decrease with a higher temperature, but the ionic surfactant is aggravate. The systematic study of binary system rheology can contribute to correctly understand and apply binary system.
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Tavassoli, Shayan, Aboulghasem Kazemi Korrani, Gary A. Pope, and Kamy Sepehrnoori. "Low-Salinity Surfactant Flooding—A Multimechanistic Enhanced-Oil-Recovery Method." SPE Journal 21, no. 03 (June 15, 2016): 0744–60. http://dx.doi.org/10.2118/173801-pa.
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Summary We have applied UTCHEM-IPhreeqc to investigate low-salinity (LS) waterflooding and LS surfactant (LSS) flooding. Numerical-simulation results were compared with laboratory experiments reported by Alagic and Skauge (2010). UTCHEM-IPhreeqc combines the UTCHEM numerical chemical-flooding simulator with IPhreeqc, the United States Geological Survey geochemical model. The IPhreeqc model was coupled to UTCHEM to model LS waterflooding as a function of geochemical reactions. The surfactant coreflood experiments were performed in vertical cores without using polymer or other mobility-control agents. These experiments were performed at a velocity greater than the critical velocity for a gravity-stable flood. After history matching the experiments, additional numerical simulations of surfactant floods at the critical velocity were run to estimate the performance under stable conditions. We also simulated a surfactant flood at higher salinity with lower interfacial tension (IFT) and compared the results with the LSS flood. These results provide new insights into LS waterflooding and surfactant flooding. Addition of surfactants prevents the retrapping of oil that was initially mobilized using LS-brine injection. The results show that the proper selection of surfactant and the design of the surfactant flood might surpass the potential benefits of LS waterflooding in terms of both higher oil recovery and lower cost. Specially, a more-effective method is expected in a stable design with no preflood.
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Bybee, Karen. "Alkaline-Surfactant/Polymer Flooding off the Cambridge Field." Journal of Petroleum Technology 52, no. 01 (January 1, 2000): 48–49. http://dx.doi.org/10.2118/0100-0048-jpt.
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