scholarly journals Optimal Design of Alkaline–Surfactant–Polymer Flooding under Low Salinity Environment

Polymers ◽  
2020 ◽  
Vol 12 (3) ◽  
pp. 626 ◽  
Author(s):  
Adi Novriansyah ◽  
Wisup Bae ◽  
Changhyup Park ◽  
Asep K. Permadi ◽  
Shabrina Sri Riswati
Keyword(s):  
Optimal Design ◽  
Weight Ratio ◽  
Linear Alkylbenzene ◽  
Low Salinity ◽  
Salinity Gradients ◽  
Asp Flooding ◽  
Glycol Monobutyl Ether ◽  
Dioctyl Sulfosuccinate ◽  
Hydrolyzed Polyacrylamide ◽  
Alkaline Surfactant Polymer

This paper presents an optimal design of alkaline–surfactant–polymer (ASP) flooding and an experimental analysis on the effects of ASP components under low formation salinity, where the assignment of salinity gradients and various phase types are limited. The phase behavior and coreflooding tests confirmed the ASP formula is optimal, i.e., 1 wt % sodium carbonate (Na2CO3) as the alkaline, 1:4 weight ratio for linear alkylbenzene sulfonate (LAS) and dioctyl sulfosuccinate (DOSS) as a surfactant, 5 wt % diethylene glycol monobutyl ether (DGBE) as a co-solvent, and hydrolyzed polyacrylamide (HPAM) as a polymer. The salinity scan was used to determine that the optimum salinity was around 1.25 wt % NaCl and its solubilization ratio was favorable, i.e., approximately 21 mL/mL. The filtration ratio determines the polymer concentrations, i.e., 3000 or 3300 mg/L, with a reduced risk of plugging through pore throats. The coreflooding test confirmed the field applicability of the proposed ASP formula with an 86.2% recovery rate of residual oil after extensive waterflooding. The optimal design for ASP flooding successfully generated phase types through the modification of salinity and can be applicable to the low-salinity environment.

scholarly journals Nonionic Surfactant to Enhance the Performances of Alkaline–Surfactant–Polymer Flooding with a Low Salinity Constraint

2020 ◽  
Vol 10 (11) ◽  
pp. 3752 ◽  
Author(s):  
Shabrina Sri Riswati ◽  
Wisup Bae ◽  
Changhyup Park ◽  
Asep K. Permadi ◽  
Adi Novriansyah
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Anionic Surfactant ◽  
Pore Volume ◽  
Salinity Gradient ◽  
Reference Case ◽  
Low Salinity ◽  
Asp Flooding ◽  
Optimum Salinity ◽  
Alkaline Surfactant Polymer

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.

ASP Flooding: A Solution for Chemical Enhanced Oil Recovery in High Temperature, Low Salinity Reservoir

2018 ◽  
Author(s):  
Cai Hongyan ◽  
Cheng Jie ◽  
Fan Jian ◽  
Luan Hexin ◽  
Wang Qing ◽  
...  
Keyword(s):  
High Temperature ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Low Salinity ◽  
Asp Flooding

Low-Salinity Chase Waterfloods Improve Performance of Cr(III)-Acetate Hydrolyzed Polyacrylamide Gel in Fractured Cores

2015 ◽  
Vol 19 (02) ◽  
pp. 331-339 ◽  
Author(s):  
Bergit Brattekås ◽  
Arne Graue ◽  
Randall S. Seright
Keyword(s):  
Fluid Flow ◽  
Water Phase ◽  
Polymer Gel ◽  
Low Salinity ◽  
Gel Swelling ◽  
The Matrix ◽  
Rupture Pressure ◽  
Salinity Water ◽  
Hydrolyzed Polyacrylamide ◽  
Blocking Capacity

Summary Polymer gels are frequently applied for conformance improvement in fractured reservoirs, where fluid channeling through fractures limits the success of waterflooding. Placement of polymer gel in fractures reduces fracture conductivity, thus increasing pressure gradients across matrix blocks during chase floods. A gel-filled fracture is reopened to fluid flow if the injection pressure during chase floods exceeds the gel-rupture pressure; thus, channeling through the fractures resumes. The success of a polymer-gel treatment, therefore, depends on the rupture pressure. Salinity differences between the gel network and surrounding water phase are known causes of gel swelling (e.g., observed in recent work on preformed particle gels). Gel swelling and its effect on fluid flow have, however, been less studied in conjunction with conventional polymer gels. By use of corefloods, this work demonstrates that low-salinity water can swell conventional Cr(III)-acetate hydrolyzed polyacrylamide (HPAM) gels, thereby significantly improving gel-blocking performance after gel rupture. Formed polymer gel was placed in fractured core plugs, and chase waterfloods were performed using four different brine compositions, of which three were low-salinity brines. The fluid flow rates through the matrix and differential pressures across the matrix and fracture were measured and shown to increase with decreasing salinity in the injected water phase. In some cores, the fractures were reblocked during low-salinity waterfloods, and gel-blocking capacity was increased above the initial level. Low-salinity water subsequently flooded the matrix during chase floods, which provided additional benefits to the waterflood. The improved blocking capacity of the gel was caused by a difference in salinity between the gel and injected water phase, which induced gel swelling. The results were reproducible through several experiments, and stable for long periods of time in both sandstone and carbonate outcrop core materials. Combining polymer gel placement in fractures with low-salinity chase floods is a promising approach in integrated enhanced oil recovery (IEOR).

scholarly journals Variations of Micropores in Oil Reservoir Before and After Strong Alkaline Alkaline-surfactant-polymer Flooding

2016 ◽  
Vol 9 (1) ◽  
pp. 257-267
Author(s):  
Yongqiang Bai ◽  
Yang Chunmei ◽  
Liu Mei ◽  
Jiang Zhenxue
Keyword(s):  
Quantitative Analysis ◽  
Crude Oil ◽  
Oil Recovery ◽  
Chemical Flooding ◽  
Sem Images ◽  
Force Microscopy ◽  
Micropore Structure ◽  
Asp Flooding ◽  
Before And After ◽  
Alkaline Surfactant Polymer

Enhanced oil recovery (EOR) provides a significant contribution for increasing output of crude oil. Alkaline-surfactant-polymer (ASP), as an effective chemical method of EOR, has played an important role in advancing crude oil output of the Daqing oilfield, China. Chemical flooding utilized in the process of ASP EOR has produced concerned damage to the reservoir, especially from the strong alkali of ASP, and variations of micropore structure of sandstones in the oil reservoirs restrain output of crude oil in the late stages of oilfield development. Laboratory flooding experiments were conducted to study sandstones’ micropore structure behavior at varying ASP flooding stages. Qualitative and quantitative analysis by cast thin section, scanning electric microscopy (SEM), atomic force microscopy (AFM) and electron probe X-Ray microanalysis (EPMA) explain the mechanisms of sandstones’ micropore structure change. According to the quantitative analysis, as the ASP dose agent increases, the pore width and pore depth exhibit a tendency of decrease-increase-decrease, and the specific ASP flooding stage is found in which flooding stage is most affective from the perspective of micropore structures. With the analysis of SEM images and variations of mineral compositions of samples, the migration of intergranular particles, the corrosions of clay, feldspar and quartz, and formation of new intergranular substances contribute to the alterations of sandstone pore structure. Results of this study provide significant guidance for further application to ASP flooding.

Alkaline/Surfactant/Polymer Chemical Flooding Without the Need for Soft Water

SPE Journal ◽  
2009 ◽  
Vol 15 (01) ◽  
pp. 184-196 ◽  
Author(s):  
Adam K. Flaaten ◽  
Quoc P Nguyen ◽  
Jieyuan Zhang ◽  
Hourshad Mohammadi ◽  
Gary A. Pope
Keyword(s):  
Sodium Carbonate ◽  
Oil Recovery ◽  
High Performance ◽  
High Salinity ◽  
Divalent Cations ◽  
Low Cost ◽  
Soft Water ◽  
Chemical Flooding ◽  
Asp Flooding ◽  
Alkaline Surfactant Polymer

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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