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.

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.

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.

Mechanisms of Enhanced Natural Imbibition With Novel Chemicals

2009 ◽  
Vol 12 (06) ◽  
pp. 912-920 ◽  
Author(s):  
Jieyuan Zhang ◽  
Quoc P. Nguyen ◽  
Adam Flaaten ◽  
Gary A. Pope
Keyword(s):  
Sodium Carbonate ◽  
Oil Recovery ◽  
Divalent Cations ◽  
Low Cost ◽  
Large Body ◽  
Carbonate Reservoirs ◽  
Alternative Methods ◽  
Type I ◽  
Water Imbibition ◽  
Fractured Carbonate

Summary A large body of literature has reflected an extensive experimental study of natural imbibition driven by local capillary pressures at high interfacial tension (IFT). However, water imbibition induced by emulsification at low IFT is not well understood. Recently, anionic surfactants have been shown to induce imbibition in mixed- and oil-wet carbonates. Sodium carbonate has been used to reduce the surfactant adsorption. However, calcium and other divalent cations can cause precipitation of the alkali unless soft water is used. This is a significant limitation of sodium carbonate. The present research both advances our understanding of the use of chemicals to enhance oil recovery (EOR) from fractured carbonate reservoirs and indicates how the process can be optimized using novel chemicals. This research applies to the improvement of oil recovery from mixed- and oil-wet fractured carbonate reservoirs. We show how to select and evaluate new chemicals as natural imbibition enhancers in carbonate rocks. A novel experimental method has also been developed to quantify the significance of capillary and emulsification driven imbibition because of the presence of the chemical imbibition enhancers. An in situ imbibition profile was visualized using a computed tomography (CT) X-ray scanning technique. The results show that formation of microemulsion strongly promotes water imbibition. The rate was highest for Winsor Type II microemulsion and lowest for Winsor Type I microemulsion. The alkalis exhibited a striking imbibition enhancement driven mainly by alteration of capillary pressure. The performance of the imbibition enhancers was found to be consistent for different core-plug sizes and boundary conditions. A novel alkali has been tested that shows a high tolerance for hardness and, thus, may be a good alternative to sodium carbonate under some conditions. The application of low-cost chemicals to EOR from fractured carbonates is an extremely significant development owing to the vast volumes of oil in such reservoirs and the lack of practical alternative methods of recovering such oil.

Coreflood Model Calibration for Alkali Surfactant Polymer Process from a High Salinity Reservoir to Design an ASP Pilot

2021 ◽  
Author(s):  
Marisely Urdaneta
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Water Saturation ◽  
Polymer Concentration ◽  
Chemical Flooding ◽  
Adsorption Parameters ◽  
Oil Saturation ◽  
The Core ◽  
Asp Flooding

Abstract This paper aims to address calibration of a coreflood Alkali Surfactant Polymer (ASP) formulation experiment through parametrization of fluid-fluid and rock-fluid interactions considering cation exchange capacity and by rock to guide an ASP pilot design. First of all, a series of chemical formulation experiments were studied in cores drilled from clastic reservoir so that displacement lab tests were run on linear and radial cores to determine the potential for oil recovery by ASP flooding and recommended the chemical formulation and flooding schemes, in terms of oil recovery. Therefore, to simulate the process, those tests performed with radial core injection were taken, because this type of test has a better representation of the fluid flow in reservoir, the fluids are injected by a perforation in the center of the core, moving in a radial direction the fluids inside the porous medium. Subsequently, displaced fluids are collected on the periphery of the core carrier and stored in graduated test tubes. The recommended test was carried out to the phase of numerical simulation and historical matching. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities based on cost-effective process implementation. Then, a radial core simulation model was designed from formulation data with porosity of 42.6%, a pore volume (PV) of 344.45 ml, radius of 7.17 cm and weight of 1225.84 g. The initial oil saturation was 0.748 PV (257.58 ml), with a critical water saturation of 0.252 PV (86.78 ml). For the simulation model historical matching, adjustments were made until an acceptable comparison was obtained with laboratory test production data through parameterization of relative permeability curves, chemical adsorption parameters, polymer viscosity, among others; resulting in an accumulated effluents production mass 37% greater for alkali than obtained in the historical, regarding to surfactant the deviation was 8% considered acceptable and for the polymer the adjustment was very close. For the injector well bottom pressure, the viscosity ratio of the mixture was considered based on the polymer concentration and the effect of the shear rate on the viscosity of the polymer as well as the effect of salinity in the alkali case. Finally, a calibrated coreflood numerical simulation model was obtained for ASP flooding to design an ASP Pilot with a residual oil saturation of 0.09 PV (31 ml) meaning 64% more recovered oil compared to a waterflooding case.

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.

A New Approach to Low-Cost, High Performance Chemical Flooding System

2010 ◽  
Author(s):  
Khaled Abdalla Elraies ◽  
Isa M. Tan ◽  
Mariyamni Bt. Awang ◽  
Taufiq Fathaddin
Keyword(s):  
High Performance ◽  
Low Cost ◽  
Chemical Flooding ◽  
New Approach

Non-Edible Oil Based Surfactant For Enhanced Oil Recovery

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Ijoma Onyemaechi
Keyword(s):  
Methyl Ester ◽  
Sodium Hydroxide ◽  
Sodium Carbonate ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Synthetic Surfactant ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Incremental Oil Recovery ◽  
Increasing Demand

Abstract After the primary and secondary oil recoveries, a substantial amount of oil is left in the reservoir which can be recovered by tertiary methods like the Alkaline-Surfactant Flood. Reasons for having some unproduced hydrocarbon in the reservoir include and not limited to the following; forces of attraction fluid contacts, low permeability, high viscous fluid, poor swept efficiency, etc. Although, it is possible to commence waterflooding together chemical injection at the start of production. Reservoir simulation with commercial simulator, could guide in selecting the most appropriate period to commence chemical flooding. In this study, the performance of a new synthetic surfactant produced from Jatropha Curcas seed was compared with that of a selected commercial surfactant in the presence of an alkaline and this shows that the non-edible Jatropha oil is a natural, inexpensive and a renewable source of energy for the production of anionic surfactants and a good substitute for commercial surfactants like Sodium Dodecyl Sulphate (SDS). The Methyl Ester Sulfonate (MES) surfactant showed no precipitation or cloudiness during stability test and was able to reduce the Interfacial Tension (IFT) to 0.018 mN/m and 0.020 mN/m in the presence of sodium carbonate and sodium hydroxide respectively as alkaline at low surfactant concentration. The optimum alkaline surfactant formulation in terms of oil recovery performance obtained from the core flooding experiment corresponds to a concentration of sodium carbonate (0.5wt%), sodium hydroxide (0.5wt%) mixed in distilled water and Methyl Ester Sulfonate (MES) surfactant (1wt%). The injection of 0.5 percentage volume of alkaline surfactant slug produced an incremental oil recovery of 26.7% and 29% respectively. With these incremental oil recoveries, increasing demand for hydrocarbons product could be met, and returns on investment portfolio will be improved.

scholarly journals Compositions and Co-occurrence Patterns of Bacterial Communities Associated With Polymer- and ASP-Flooded Petroleum Reservoir Blocks

2020 ◽  
Vol 11 ◽  
Author(s):  
Guoling Ren ◽  
Jinlong Wang ◽  
Lina Qu ◽  
Wei Li ◽  
Min Hu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Bacterial Communities ◽  
Chemical Properties ◽  
Oil Production ◽  
Chemical Flooding ◽  
Petroleum Reservoir ◽  
Promising Alternative ◽  
Asp Flooding ◽  
Production Wells ◽  
Occurrence Patterns

Polymer flooding technology and alkaline-surfactant-polymer (ASP) flooding technology have been widely used in some oil reservoirs. About 50% of remaining oil is trapped, however, in polymer-flooded and ASP-flooded reservoirs. How to further improve oil recovery of these reservoirs after chemical flooding is technically challenging. Microbial enhanced oil recovery (MEOR) technology is a promising alternative technology. However, the bacterial communities in the polymer-flooded and ASP-flooded reservoirs have rarely been investigated. We investigated the distribution and co-occurrence patterns of bacterial communities in ASP-flooded and polymer-flooded oil production wells. We found that Arcobacter and Pseudomonas were dominant both in the polymer-flooded and ASP-flooded production wells. Halomonas accounted for a large amount of the bacterial communities inhabiting in the ASP-flooded blocks, whereas they were hardly detected in the polymer-flooded blocks, and the trends for Acetomicrobium were the opposite. RDA analysis indicated that bacterial communities in ASP-flooded and polymer-flooded oil production wells are closely related to the physical and chemical properties, such as high salinity and strong alkaline, which together accounted for 56.91% of total variance. Co-occurrence network analysis revealed non-random combination patterns of bacterial composition from production wells of ASP-flooded and polymer-flooded blocks, and the ASP-flooded treatment decreased bacterial network complexity, suggesting that the application of ASP flooding technology reduced the tightness of bacterial interactions.

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.

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