A Mechanistic Integrated Geochemical and Chemical-Flooding Tool for Alkaline/Surfactant/Polymer Floods

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 32-54 ◽  
Author(s):  
Aboulghasem Kazemi Korrani ◽  
Kamy Sepehrnoori ◽  
Mojdeh Delshad
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
The United States ◽  
Mineral Dissolution ◽  
Mechanistic Modeling ◽  
United States Geological Survey ◽  
Chemical Flooding ◽  
Exchange Reactions ◽  
Asp Flooding ◽  
Alkaline Surfactant Polymer

Summary Mechanistic simulation of alkaline/surfactant/polymer (ASP) flooding considers chemical reactions between the alkali and the oil to form in-situ soap and reactions between the alkali and the minerals and brine. A comprehensive mechanistic modeling of such process remains a challenge, mainly caused by the complicated ASP phase behavior and the complexity of geochemical reactions that occur in the reservoir. Because of the lack of the microemulsion phase and/or lack of reactions that may lead to the consumption of alkali and resulting lag in the pH, a simplified ASP phase behavior is often used. A state-of-the-art geochemical package, IPhreeqc, of the United States Geological Survey was coupled with UTCHEM, an in-house research chemical-flooding reservoir simulator developed at The University of Texas at Austin (UT), for a robust, flexible, and accurate integrated tool to mechanistically model ASP floods. UTCHEM has a comprehensive three-phase (water, oil, microemulsion) flash package for the mixture of surfactant and soap as a function of salinity, temperature, and cosolvent concentration. Through this integrated tool, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, surface complexation, and ion exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium and kinetic conditions. Italic words are defined in Appendix A. IPhreeqc has rich databases of chemical species and also the flexibility to include the alkaline reactions required for modeling ASP floods. Hence, to the best of our knowledge, for the first time, the important aspects of ASP flooding are considered. An algorithm is presented for modeling the geochemistry in an implicit-in-pressure-and-explicit-in-concentration solution algorithm. Finally, we show how to apply the integrated tool, UTCHEM-IPhreeqc, to match three different reaction-related chemical-flooding processes: ASP flooding in an acidic active crude oil, ASP flooding in a nonacidic crude oil, and alkaline/cosolvent/polymer flooding.

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.

Mechanistic Modeling of Low-Salinity Waterflooding Through Coupling a Geochemical Package With a Compositional Reservoir Simulator

2016 ◽  
Vol 19 (01) ◽  
pp. 142-162 ◽  
Author(s):  
Aboulghasem Kazemi Korrani ◽  
Gary R. Jerauld ◽  
Kamy Sepehrnoori
Keyword(s):  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Mechanistic Modeling ◽  
Water Soluble ◽  
Exchange Reactions ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Reservoir Simulator

Summary Low-salinity waterflooding is an emerging enhanced-oil-recovery (EOR) technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher-salinity waterflooding. Although there are many low-salinity experimental results reported in the literature, publications on modeling this process are rare. Although there remains some debate regarding the mechanisms of low salinity waterflooding process (LoSal EOR®)*, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Because no comprehensive geochemical-based modeling has been applied in this area, it was decided to couple a state-of-the-art geochemical package, IPhreeqc (Charlton and Parkhurst 2011), developed by the US Geological Survey, with UTCOMP (Chang 1990), the compositional reservoir simulator developed by The University of Texas at Austin. A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium (away from the wellbore) and kinetic (near wellbore) conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components—e.g., carbon dioxide (CO2), methane (CH4), and acidic/basic components of the crude—on buffering the aqueous pH value and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constraints are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low-salinity waterflooding. Different geochemical-based approaches to modeling wettability change in sandstones (e.g., interpolation on the basis of total ionic strength and multicomponent ion exchange through surface complexation of the organometallic components) were implemented in UTCOMP-IPhreeqc, and the integrated tool is then used to match and interpret a low-salinity experiment published by Kozaki (2012) and the field trial performed by BP at the Endicott field.

A Systematic Laboratory Approach to Low-Cost, High-Performance Chemical Flooding

2009 ◽  
Vol 12 (05) ◽  
pp. 713-723 ◽  
Author(s):  
Adam Flaaten ◽  
Quoc P. Nguyen ◽  
Gary A. Pope ◽  
Jieyuan Zhang
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
High Performance ◽  
Low Cost ◽  
Surfactant Adsorption ◽  
Chemical Flooding ◽  
Chemical Mixtures ◽  
Asp Flooding ◽  
Saline Brine

Summary We present a systematic study of laboratory tests of alternative chemical formulations for a chemical flood design and application. Aqueous and microemulsion phase behavior tests have previously been shown to be a rapid, inexpensive, and highly effective means to select the best chemicals and minimize the need for relatively expensive coreflood tests. Microemulsion phase behavior testing was therefore conducted using various combinations of surfactants, cosolvents, and alkalis with a particular crude oil and in reservoir conditions of interest. Branched alcohol propoxy sulfates and internal olefin sulfonates showed high performance in these tests, even when mixed with both conventional and novel alkali agents. Systematic screening methods helped tailor and fine tune chemical mixtures to perform well under the given design constraints. The best chemical formulations were validated in coreflood experiments, and compared in terms of both oil recovery and surfactant retention in cores. Each of the four best formulations tested in corefloods gave nearly 100% oil recovery and very low surfactant adsorption. The two formulations with conventional and novel alkali agents gave almost zero surfactant retention. In standard practice, soft water must be used with alkali, but we show how alkali-surfactant-polymer (ASP) flooding can be used in this case even with very hard saline brine. Introduction Many mature reservoirs under waterflood have low economic production rates despite having as much as 50 to 75% of the original oil still in place. These reservoirs are viable candidates for chemical enhanced oil recovery (EOR) that uses both surfactant to reduce oil/water interfacial tension (IFT) and polymer to improve sweep efficiency. However, designing these aqueous chemical mixtures is complex and must be tailored to the reservoir rock and fluid (i.e., crude oil and formation brine) properties of the application. The early success of a systematic laboratory approach to low-cost, high performance chemical flooding depends on the efficiency of designing a formula for coreflood injection in accordance with sound evaluation criteria. A general, a three-stage procedure has been developed previously to screen hundreds of potential chemicals (i.e., surfactant, cosurfactant, cosolvent, alkali, polymer, and electrolytes), and arrive at a mixture having good recovery of residual oil in cores (Jackson 2006; Levitt 2006; Levitt et al. 2006). Additionally, furthering laboratory and field-testing in this area contributes to an expanding research database to help broaden reservoir types that can become candidates for routine chemical EOR application. This paper describes a systematic laboratory approach to low cost, high performance chemical flooding, and explores novel approaches to ASP flooding in reservoirs containing very hard saline brines. The design strategy first uses microemulsion phase behavior experiments to quickly select and optimize concentrations of injected chemicals. Assessment of formula optimization strategies are carried out through varying surfactant-to-cosurfactant ratio, reducing cosolvent concentration, reducing total surfactant concentration, selecting a suitable alkali, and using formation brine in the injection mixture. Formulations performing well in phase behavior are validated in coreflood experiments that adhere to necessary design criteria such as pressure and salinity gradients, surfactant adsorption, and capillary effects. We illustrate the application of our design approach in prepared Berea sandstone cores previously waterflooded with very hard saline brine, and show how ASP flooding can use some of the same brine in the chemical formulation. Conventional ASP flooding requires soft water that may not always be available, and softening hard brines can be very costly or infeasible in many cases depending on the location and other factors. These new results demonstrate high tolerance to both salinity and hardness of the high performance surfactants, and how novel alkalis--in particular sodium metaborate--can provide similar benefits in such harsh environments as sodium carbonate has shown in environments without divalent cations. This experimental success begins to vastly increase the range of conditions for economical EOR using chemicals.

Favorable Attributes of Alkaline-Surfactant-Polymer Flooding

SPE Journal ◽  
2008 ◽  
Vol 13 (01) ◽  
pp. 5-16 ◽  
Author(s):  
Shunhua Liu ◽  
Danhua Zhang ◽  
Wei Yan ◽  
Maura Puerto ◽  
George J. Hirasaki ◽  
...  
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Anionic Surfactants ◽  
Naphthenic Acids ◽  
Mobility Control ◽  
Alkaline Solutions ◽  
Synthetic Surfactant ◽  
Optimal Salinity ◽  
Interfacial Tensions ◽  
Alkaline Surfactant Polymer

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).

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.

Advantages of an APS/AES Seawater-Based Surfactant Polymer Formulation

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3494-3506
Author(s):  
Jeffrey G. Southwick ◽  
Carl van Rijn ◽  
Esther van den Pol ◽  
Diederik van Batenburg ◽  
Arif Azhan ◽  
...  
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Salinity Gradient ◽  
Low Complexity ◽  
Fine Tuning ◽  
Reservoir Rock ◽  
Similar Amount ◽  
Type I ◽  
Chemical Flooding

Summary A low-complexity chemical flooding formulation has been developed for application in offshore environments. The formulation uses seawater with no additional water treatment beyond that which is normally performed for waterflooding (filtration, deoxygenation, etc.). The formulation is a mixture of an alkyl propoxy sulfate (APS) and an alkyl ethoxy sulfate (AES) with no cosolvent. With seawater only (no salinity gradient), the blend of APS and AES gives substantially higher oil recovery than a blend of APS and internal olefin sulfonate (IOS) in outcrop sandstone. This formulation also reduces complexity, increases robustness, and potentially improves project economics for onshore projects as well. It is shown that the highest oil recovery is obtained with surfactant blends that produce formulations that are underoptimum (Winsor Type I phase behavior) with reservoir crude oil. Also, these underoptimum formulations avoid the high-injection pressures that are seen with optimum formulations in low-permeability outcrop rock. The formulation recovers a similar amount of oil in reservoir rock in the swept zone. Overall recovery in reservoir rock is lower than outcrop sandstone due to greater heterogeneity, which causes bypassing of crude oil. A successful formulation was developed by first screening surfactants for phase behavior then fine tuning the formulation based on insights developed with corefloods in consistent outcrop rocks. The consistency of the outcrop is essential to understand cause and effect. Then, final floods were performed in reservoir rock to confirm that low interfacial tension (IFT) is propagated through the core.

Mechanistic Modeling of Alkaline/Surfactant/Polymer Floods

2009 ◽  
Vol 12 (04) ◽  
pp. 518-527 ◽  
Author(s):  
Hourshad Mohammadi ◽  
Mojdeh Delshad ◽  
Gary A. Pope
Keyword(s):  
Phase Behavior ◽  
Chemical Reactions ◽  
Oil Recovery ◽  
Numerical Models ◽  
Naphthenic Acids ◽  
Mechanistic Modeling ◽  
Synthetic Surfactant ◽  
Recovery Method ◽  
Optimum Salinity ◽  
Alkaline Surfactant Polymer

Summary Alkaline/surfactant/polymer (ASP) flooding is of increasing interest and importance because of high oil prices and the need to increase oil production. The benefits of combining alkali with surfactant are well established. The alkali has very important benefits such as lowering interfacial tension (IFT) and reducing adsorption of anionic surfactants that decrease costs and make ASP a very attractive enhanced-oil-recovery method, provided that the consumption is not too large and the alkali can be propagated at the same rate as the synthetic surfactant and polymer. However, the process is complex, so it is important that new candidates for ASP be selected taking into account the numerous chemical reactions that occur in the reservoir. The reaction of acid and alkali to generate soap and its subsequent effect on phase behavior is the most crucial for crude oils containing naphthenic acids. Mechanistic simulation of the ASP flood considering the chemical reactions, alkali consumption, and soap generation and the effect on the phase behavior is the key to success of future field operations. Using numerical models, the process can be designed and optimized to ensure the proper propagation of alkali and effective soap and surfactant concentrations to promote low IFT and a favorable salinity gradient. In this paper, we describe the ASP module of the UTCHEM simulator, which is the University of Texas chemical compositional simulator, with particular attention to phase behavior and the effect of soap on optimum salinity and solubilization ratio. Phase behavior data are presented for sodium carbonate and a blend of surfactants with an acidic crude oil that followed the conventional Winsor phase transition with significant three-phase regions even at low surfactant concentrations. The solubilization data at different oil concentrations were successfully modeled using Hand's rule. Optimum salinity and solubilization ratio were correlated with soap mole fractions using mixing rules. ASP coreflood results were successfully modeled taking into account the aqueous reactions, alkali/rock interactions, and phase behavior of soap and surfactant. Mechanistic simulations give insights into the propagation of alkali, soap, and surfactant in the core and aid in future coreflood and field-scale ASP designs.

scholarly journals The Effect of Silica Dissolution on Reservoir Properties during Alkaline-Surfactant-Polymer (ASP) Flooding

2021 ◽  
Author(s):  
Ahmed Fatah
Keyword(s):  
Physical Properties ◽  
Pore Volume ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Reservoir Properties ◽  
Silica Dissolution ◽  
The Core ◽  
Asp Flooding ◽  
The Impact ◽  
Alkaline Surfactant Polymer

Chemical flooding is one of the effective methods to recover large volumes of oil from sandstone formations after primary depletion. However, silica dissolution often occurs during Alkaline-Surfactant-Polymer (ASP) flooding, affecting the petro-physical properties of the formation. To address this issue, samples from Berea sandstone formations were treated with various brine solutions, through static tube tests and core flooding experiments. Analytical tests such as DR/2800 spectrophotometer and scanning electron microscope were used to evaluate the silica solubility and the alteration in mineral content. The results indicated that the silicate contents decreased after the saturation due to silica solubility in the solution. Increasing brine salinity to 40,000ppm and introducing Magnesium and Calcium ions to the solution, reduces the silicate contents by 5.03 % and 7.32 %. Moreover, saturating the samples with ASP solution, further reduced the silicate contents by 14.86 %. This reduction is associated with a relative increase in silica solubility and pH of the solution. Silica dissolution affects the pore microstructure, which resulted in increasing the porosity and pore volume after the core flooding. The injection of the ASP solution increased the porosity by 5.83%, thus the pore volume increased from 17.72 to 18.76cc. This is associated with the high silica solubility and the increase of solution pH in the ASP solution. The permeability of the samples generally reduced after the core flooding, due to the silica solubility. However, injecting the ASP solution, resulted in a major reduction of the permeability by more than 75%. These changes in the petro-physical properties can lead to severe formation damage, and affect hydrocarbon production. This study assists in understanding the impact of silica dissolution during ASP treatment and addresses the factors involved. Efficient utilization of chemical flooding can help mitigating silicate scaling within the formation, and extend field productivity.

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