Alkaline-Surfactant-Polymer Flooding of the Cambridge Minnelusa Field

Vargo, Jay; Turner, Jim; Bob, Vergnani; Pitts, Malcolm; Wyatt, Kon; Surkalo, H.; Patterson, David

doi:10.2118/68285-pa

Cited by 110 publications

(48 citation statements)

References 8 publications

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“…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).…”

Section: Introductionmentioning

confidence: 99%

Favorable Attributes of Alkaline-Surfactant-Polymer Flooding

et al. 2008

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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 C 16-17 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.

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Section: Introductionmentioning

confidence: 99%

Favorable Attributes of Alkaline-Surfactant-Polymer Flooding

et al. 2008

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“…Relatively few field tests of the process have been carried out. Commercial success is claimed in at least two tests (7,8) .…”

Section: Alkaline-surfactant-polymer (Asp) Floodingmentioning

confidence: 99%

Micellar Flooding and ASP-Chemical Methods for Enhanced Oil Recovery

Thomas¹,

Ali²

2001

Journal of Canadian Petroleum Technology

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Chemical flooding methods hold particular attraction for recovering the "residual oil" left in the reservoir after waterflooding. This paper describes and compares the results for two promising methods, viz. micellar flooding and alkaline-surfactant-polymer (ASP) flooding processes. Both of these methods have been tested successfully in the field, notably micellar flooding. Laboratory results are described for micellar floods in consolidated sandstone cores as well as in unconsolidated sand packs, including a three-dimensional model, equipped with horizontal or vertical wells. Floods were also carried out in unconsolidated cores using combinations of an alkali, surfactant and a polymer. Individual slugs were injected sequentially in some of the experiments, while the three components were mixed and injected as a single slug in other experiments. Oil recoveries in the two cases were similar. Results for the two processes are compared and contrasted, showing that, on the basis of oil volume recovered per unit mass of the chemical used, the two processes are similar, with micellar flooding having an edge. However, on the basis of total oil recovery, micellar flooding is the superior process, with oil recoveries ranging from 50 to 80﹪ of the oil left in the porous medium after a waterflood. Practical implications of the results are discussed. Introduction Among chemical flooding methods, micellar flooding and alkaline- surfactant-polymer (ASP) flooding processes are particularly effective for recovering a large fraction of the conventional oil (25 °CDATA[API, or higher) left in the reservoir after a waterflood, which could be as much as 60﹪ of the original oil in place. Many field tests of the micellar flooding process and several of ASP have established the effectiveness of these methods for mobilizing waterflood residual oil. The present laboratory study compares and contrasts the two processes, based on tertiary floods in sand packs and Berea sandstone cores. A number of investigators have noted the use of an alkali for reducing the divalent ion content and increasing the negative charge of the rock with a view to reducing chemical loss(1,2). Surkalo(3) reported the alkaline-surfactant-polymer (ASP) process as an alternative to micellar flooding. Several field tests have also been reported. Another function of alkali, if the Acid No. of the crude oil is large enough (> 0.5 mg KOH/g crude oil) is that the alkali may react with the acid components to form a surfactant in situ. Other factors, such as gravity segregation of alkali solutions, rate of diffusional and mechanical mixing, and subsequent mixing of surfactant formed would limit the effectiveness of this mechanism. The Process Chemical flooding methods are based on improving the mobility ratio, i.e., making the mobility of the displacing flood less than or equal to the mobility of the displaced fluid, and increasing the capillary number, mainly by making the interfacial tension (IFT) between the displacing and the displaced phases small, usually by about 1,000 fold. Other effects are also present, such as formation of macro- and microemulsions, formation of precipitates, wettability changes, relative permeability shifts, etc. Macroemulsions may improve the mobility ratio through drop entrainment and entrapment. At the same time, surfactant adsorption occurs on the rock surface.

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“…Thus, with the popularization of polymer flooding technology, how to further enhance oil recovery after polymer flooding attracts more and more concerns. Therefore, many technologies including polymer-surfactant flooding [10,11], alkaline-surfactant-polymer flooding [12][13][14], foam flooding [15][16][17][18], and gel treatment [19][20][21][22] have been developed to further enhance oil recovery by improving the sweep efficiency and oil displacement efficiency. Gel treatment has been recognized as an effective technology to enhance oil recovery after polymer flooding.…”

Section: Introductionmentioning

confidence: 99%

Investigation of Injection Strategy of Branched-Preformed Particle Gel/Polymer/Surfactant for Enhanced Oil Recovery after Polymer Flooding in Heterogeneous Reservoirs

Hou

et al. 2018

Energies

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Abstract:The heterogeneous phase combination flooding (HPCF) system which is composed of a branched-preformed particle gel (B-PPG), polymer, and surfactant has been proposed to enhance oil recovery after polymer flooding in heterogeneous reservoirs by mobility control and reducing oil-water interfacial tension. However, the high cost of chemicals can make this process economically challenging in an era of low oil prices. Thus, in an era of low oil prices, it is becoming even more essential to optimize the heterogeneous phase combination flooding design. In order to optimize the HPCF process, the injection strategy has been designed such that the incremental oil recovery can be maximized using the corresponding combination of the B-PPG, polymer, and surfactant, thereby ensuring a more economically-viable recovery process. Different HPCF injection strategies including simultaneous injection and alternation injection were investigated by conducting parallel sand pack flooding experiments and large-scale plate sand pack flooding experiments. Results show that based on the flow rate ratio, the pressure rising area and the incremental oil recovery, no matter whether the injection strategy is simultaneous injection or alternation injection of HPCF, the HPCF can significantly block high permeability zone, increase the sweep efficiency and oil displacement efficiency, and effectively improve oil recovery. Compared with the simultaneous injection mode, the alternation injection of HPCF can show better sweep efficiency and oil displacement efficiency. Moreover, when the slug of HPCF and polymer/surfactant with the equivalent economical cost is injected by alternation injection mode, as the alternating cycle increases, the incremental oil recovery increases. The remaining oil distribution at different flooding stages investigated by conducting large-scale plate sand pack flooding experiments shows that alternation injection of HPCF can recover more remaining oil in the low permeability zone than simultaneous injection. Hence, these findings could provide the guidance for developing the injection strategy of HPCF to further enhance oil recovery after polymer flooding in heterogeneous reservoirs in the era of low oil prices.

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Alkaline-Surfactant-Polymer Flooding of the Cambridge Minnelusa Field

Cited by 110 publications

References 8 publications

Favorable Attributes of Alkaline-Surfactant-Polymer Flooding

Favorable Attributes of Alkaline-Surfactant-Polymer Flooding

Micellar Flooding and ASP-Chemical Methods for Enhanced Oil Recovery

Investigation of Injection Strategy of Branched-Preformed Particle Gel/Polymer/Surfactant for Enhanced Oil Recovery after Polymer Flooding in Heterogeneous Reservoirs

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