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

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 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.

Alkaline/Surfactant/Polymer Flood: From the Laboratory to the Field

2011 ◽  
Vol 14 (06) ◽  
pp. 702-712 ◽  
Author(s):  
W. M. Stoll ◽  
H.. al Shureqi ◽  
J.. Finol ◽  
S. A. Al-Harthy ◽  
S.. Oyemade ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Test Tube ◽  
Full Field ◽  
Asp Flooding ◽  
Chemical Eor ◽  
Single Well ◽  
Hydrocarbon Gas ◽  
Reservoir Simulation Model ◽  
Petroleum Development ◽  
Alkaline Surfactant Polymer

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.

Scaling Laws and Forecasting Techniques of Silicate in ASP Flooding

2013 ◽  
Vol 850-851 ◽  
pp. 221-224
Author(s):  
Xin Sui ◽  
Hai Ming Wu ◽  
Bao Hui Wang ◽  
Dong Jing ◽  
Hong Jun Wu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Scaling Laws ◽  
Ph Value ◽  
Oil Production ◽  
Asp Flooding ◽  
Aluminum Ions ◽  
Calcium Magnesium ◽  
Set Up ◽  
Lower Temperature ◽  
Alkaline Surfactant Polymer

Served as alkaline-surfactant-polymer flooding for the enhanced oil recovery, alkaline-surfactant-polymer has widely been employed for Chinese oil production. In the practical opinion, the silicate scaling, which was formed by alkali, would harm layer gradually and affect oilfield production seriously. For the reason, in this paper, the phase diagrams of silicate scale were obtained in three different systems, including single silicon system, calcium/ magnesium/ silicon coexistence system, and calcium/ magnesium/ silicon/ aluminum coexistence system. The results showed that, other ions would affect the morphology and process of silicate scaling. In the experimental research range, silicate scaling is more easily to form with the lower temperature or pH value. The mixing scale was formed by absorption of silicate scale on the surface of carbonate scale. The aluminosilicate was formed by aluminum ions and silicon. The silicon scale forecasting model and equation of three different systems in ASP flooding with alkali was set up according to lab date. These data can provide theoretical basis for preventing scaling in oil production

An Experimental Study on Efficient Demulsification for Produced Emulsion in Alkaline/Surfactant/Polymer Flooding

2021 ◽  
pp. 1-34
Author(s):  
Yang Song ◽  
Yunfei Xu ◽  
Zhihua Wang
Keyword(s):  
Electric Field ◽  
Oil Recovery ◽  
Pulse Electric Field ◽  
Water Separation ◽  
Efficient Treatment ◽  
Peak Current ◽  
Charge Neutralization ◽  
Asp Flooding ◽  
Dehydration Effect ◽  
Alkaline Surfactant Polymer

Abstract Tertiary oil recovery technologies, exampled as alkaline/surfactant/polymer (ASP) flooding, can enhance oil recovery (EOR) as an important oil displacement technology noteworthy in the present oilfields. However, it is the fact that the produced emulsion droplets have strong electronegativity, which will lead to the destabilization of electric field and affect the dehydration effect in the process of electric dehydration. This paper innovatively proposed an efficient demulsification scheme, which uses platinum chloride (PAC) as a chemical regulator to control electric field destabilization through the charge neutralization mechanism, and then introduces demulsifier to promote oil-water separation. Furthermore, the dehydration temperature, power supply mode and electric field parameters are optimized so as to achieve superior dehydration effect of ASP flooding produced liquid. The results indicate that PAC as a chemical regulator by exerting charge neutralization and electrostatic adsorption mechanism could reduce the electronegativity of the emulsified system, decrease the peak current of dehydration, shorten the duration of peak current of dehydration, improve the response performance of the electric field, and increase dehydration rate in ASP flooding dehydration process. When the demulsifier dosage is 100 to 120 mg/L, using the composite separation process with the dehydration temperature of 45 to 50 °C for the thermochemical separation stage and 60 °C in the electrochemical dehydration stage and AC-DC composite electric field or pulse electric field can achieve better dehydration effect. The investigations in this study will provide support and basis for the efficient treatment of ASP flooding produced emulsion.

Osmosis as Mechanism for Low-Salinity Enhanced Oil Recovery

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1227-1235 ◽  
Author(s):  
K.. Sandengen ◽  
A.. Kristoffersen ◽  
K.. Melhuus ◽  
L. O. Jøsang
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Salinity Gradient ◽  
Spontaneous Imbibition ◽  
Model Systems ◽  
Wettability Alteration ◽  
Connate Water ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Summary We believe that osmosis has been overlooked as a possible mechanism for observed low-salinity enhanced-oil-recovery (EOR) effects. Osmosis can occur in an oil/water/rock system when injecting low-salinity water, because the system is full of an excellent semipermeable membrane—the oil itself. In the present work, water transport through oil films was visualized both in 2D micromodels and in sandstone cores imaged in a microcomputed tomography (CT). After treating these model systems with hexamethyldisilazane (HMDS) to render them more oil-wet, water became discontinuous, and it was possible to establish osmotic gradients. Either expansion or contraction of the connate water was observed, depending on the direction of the imposed salinity gradient. Because osmosis could be the underlying mechanism for low-salinity EOR, two changes in research strategy are proposed: Most importantly, the use of spontaneous-imbibition tests as evidence for wettability alteration in low-salinity water should be critically reinvestigated. This is because observed production could have stemmed from “osmotic expansion” of the connate water rather than wettability change. Second, much research focus should be shifted from sandstone reservoirs to fractured oil-wet carbonates. Osmosis potentially yields larger responses for the latter reservoir type, whereas from a mechanistic perspective the reason behind low-salinity EOR functioning in both sandstones and carbonates deserves further attention.

scholarly journals Experimental Investigation of Temperature Effects on Low Salinity Enzyme Enhanced Oil Recovery Process

2020 ◽  
Vol 17 (3) ◽  
pp. 156-164
Author(s):  
Tinuola H. Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Pore Volume ◽  
Temperature Effects ◽  
High Salinity ◽  
Effect Of Temperature ◽  
Core Flooding ◽  
Low Salinity ◽  
Recovery Processes ◽  
Brine Injection

In this paper, the effect of temperature on low salinity brine and combined low salinity enzyme oil recovery processes in sandstone rock sample was experimentally investigated. The core flooding displacement tests were conducted with the injection of the enzyme in post-tertiary mode after secondary high salinity brine and tertiary low salinity brine injection processes. Effluents analyses of each of the flooding were carried out and used to evaluate the effect of temperature on rock-fluid interactions and enhanced oil recovery processes. The results showed that tertiary low salinity brine injection and post-tertiary enzyme injection increased recovery by 2.4-8.72% over the secondary high salinity brine flooding at 25 oC. Also, increase in oil recovery (0.57-13.18%) was observed with increase in the system temperature from 25 oC to 70 oC. Furthermore, the effluent of the 70 oC flooding was associated with the earliest low salinity brine ionic breakthrough front at 10 injected pore volume, while the 25 oC flooding breakthrough front occurred at 22 pore volume. However, no obvious effect of temperature on pH of the effluents was observed with all the floodings, but temperature effects were observed with the conductivity and ionic concentrations of all the effluents as evident by varied breakthrough times. Hence, the observed increased recovery in this study is attributable to combined effects of electric double-layer expansion, oil viscosity reduction and interfacial tension reduction. This novel study of the combined low salinity enzyme injection process is significant for the design of enzyme enhanced oil recovery processes. Keywords: Enhanced oil recovery, enzyme, sandstone, low salinity, core flooding, temperature.

Sign in / Sign up

Export Citation Format

Share Document