Surfactant Enhanced Oil Recovery Research Articles

New Trends in Biosurfactants: From Renewable Origin to Green Enhanced Oil Recovery Applications.

Enhanced oil recovery (EOR) processes are technologies used in the oil and gas industry to maximize the extraction of residual oil from reservoirs after primary and secondary recovery methods have been carried out. The injection into the reservoir of surface-active substances capable of reducing the surface tension between oil and the rock surface should favor its extraction with significant economic repercussions. However, the most commonly used surfactants in EOR are derived from petroleum, and their use can have negative environmental impacts, such as toxicity and persistence in the environment. Biosurfactants on the other hand, are derived from renewable resources and are biodegradable, making them potentially more sustainable and environmentally friendly. The present review intends to offer an updated overview of the most significant results available in scientific literature on the potential application of biosurfactants in the context of EOR processes. Aspects such as production strategies, techniques for characterizing the mechanisms of action and the pros and cons of the application of biosurfactants as a principal method for EOR will be illustrated and discussed in detail. Optimized concepts such as the HLD in biosurfactant choice and design for EOR are also discussed. The scientific findings that are illustrated and reviewed in this paper show why general emphasis needs to be placed on the development and adoption of biosurfactants in EOR as a substantial contribution to a more sustainable and environmentally friendly oil and gas industry.

Wettability modification effects on relative permeability end-points: Comparative analysis of surfactant agents for enhanced oil recovery

This research examines the impact of wettability alteration on the end points of relative permeability, a crucial property of fluids and porous media that influences the displacement processes of immiscible fluids through such media. The estimation of the mobility ratio for oil recovery relies on these end points, which are influenced by connate water saturation and residual oil saturation. To investigate this relationship, carbonate rock is generally subjected to wettability alteration using surfactant agents, and core flooding is employed to determine the relative permeability before and after the alteration. The wettability of the rock is commonly assessed through contact angle measurements. Two surfactants, TritonX-100 (Tx-100) and Cedar, were tested in reducing the wettability of the porous media for oil. The contact angle measurements revealed that Tx-100 was more effective for this purpose than Cedar. Furthermore, the relative permeability tests indicated that both surfactants decreased residual oil saturation, but Tx-100 also improved system pressure. In contrast, Cedar reduced residual oil saturation but increased system pressure, possibly because of its high viscosity. The results also demonstrate that injecting Tx-100 leads to a 14% increase in ultimate oil recovery compared with water injection, while Cedar injection increased the recovery factor by 5%. This difference may be attributed to the incomplete coverage of the pore wall by Cedar or its weaker chemical structure than Tx-100. Notably, in carbonate cores, neither non-ionic surfactant enhanced oil recovery.

Enhanced Oil Recovery by Surfactant Injection was improved during the Last 50 Years Thanks to the Multivariable HLD Formulation Equation

This report reviews the progress in Enhanced Oil Recovery (EOR) through surfactant injection over the past half century from 1974, with a specific focus on the role of the multivariable Hydrophilic-Lipophilic Deviation (HLD) formulation equation in different expressions. This equation has been instrumental in optimizing surfactant formulations for EOR, enabling the fine-tuning of surfactant types and properties to match specific reservoir conditions like brine salinity, crude characteristic, temperature and even pressure. This short assesment discusses the evolution of surfactant types, and their impact on EOR efficiency for a given reservoir specifications. It highlights the role of intramolecular and intermolecular mixing in surfactant performance, and the benefits of using a multivariable HLD equation to predict and optimize the injected formulation. Furthermore, it explores the challenges and solutions related to surfactant adsorption, aggregation, precipitation, and effect on phase behavior and interfacial tension, and how these factors have to be considered when using surfactants for EOR projects. This review aims to address the existing gaps in the literature, such as the complex effects of surfactant mixtures with insensitivity to temperature and injected composition (amphiphilic concentration and water/oil ratio) that make difficult to propose a unified approach for different petroleum reservoirs. It concludes a discussion on the state of the art and future of surfactant EOR, emphasizing the need for continued research and collaboration across academic and industrial sectors

Surfactant Enhanced Oil Recovery Improves Oil Recovery in a Depleted Eagle Ford Unconventional Well: A Case Study

Summary A simple huff “n” puff (HnP) injection and flowback using a nonionic surfactant solution to drive enhanced oil recovery (EOR) in a depleted Eagle Ford “black oil” unconventional well has been executed and analyzed. The pilot injection was performed in December 2020, with pressures below the estimated fracture gradient. More than 12,300 bbl of surfactant solution were injected into the 6,000-ft lateral. In January 2021, the well was put back on production with oil and water flow rate data being gathered and samples collected. Within 3 months of the well being put back onto production after surfactant stimulation, the well produced at oil rates over five times what it had produced before stimulation. The current oil rates (through October 2022; 22 months after stimulation) are still twice the prestimulation rates. Using a long-term hyperbolic fit to historical data as the “most likely” production scenario in the absence of stimulation as a “baseline,” incremental recovery was estimated using the actual oil production data to date. Economic analysis with prevailing West Texas Intermediate (i.e., WTI) prices at the time of production and the known costs of the pilot result in project payout time less than 1 year and project internal rate of return in excess of 80%, with only incremental production to date. These results prove the potential for technoeconomic viability of HnP EOR techniques using surfactants for wettability alteration in depleted unconventional oil wells. The well was chosen from a portfolio of unconventional Eagle Ford black oil window wells that were completed in the 2012–2014 time frame. The goal of the test was to demonstrate successful application of laboratory work to the field and economic viability of surfactant-driven water imbibition as a means of incremental EOR. The field design was based on laboratory work completed on oil and brine samples from the well of interest, with rock sampled from a nearby well at the same depth. The technical and economic objectives of the field test were to (1) inject surfactant solution to contact sufficient matrix surface area that measurable and economically attractive amounts of oil could be mobilized, (2) measure the amount of surfactant produced in the flowback stream to determine the amount of surfactant retained in the reservoir, and (3) prove the concept of using wettability alteration in conjunction with residual well energy in a depleted well to achieve economically attractive incremental recovery. Surfactant selection was completed in the laboratory using oil and brine gathered from potential target wells, and rock from nearby wells completed in the same strata. Several surfactant formulations were tested, and a final nonionic formulation was chosen on the basis of favorable wettability alteration and improved spontaneous imbibition recovery. The design for the pilot relied on rules of thumb derived from unconventional completion parameters. Rates, pressures, and injectant composition were carefully controlled for the single-day “bullhead” injection. Soak time between injection and post-stimulation restart of production was inferred from laboratory-scale imbibition trials. Post-stimulation samples were gathered, while daily oil and water rates were monitored since production restart. Flowback samples were analyzed for total dissolved solids (TDS), ions, and surfactant concentration.

Experimental Mechanism for Enhancing Oil Recovery by Spontaneous Imbibition with Surfactants in a Tight Sandstone Oil Reservoir

This study aims to investigate the mechanism behind surfactant enhanced oil recovery under reservoir conditions through experiments on spontaneous imbibition with surfactants. The tight sandstone samples are characterized using cast thin section (CTS), high-pressure mercury intrusion (HPMI), and nuclear magnetic resonance (NMR) to determine their clay mineral composition, pore size distribution, and fluid distribution. Spontaneous imbibition experiments are then conducted using formation water and surfactant solutions as imbibition liquids, with three different types of surfactants─dodecylbenzene sulfonate (DBS), sodium dodecyl sulfate (SDS), and ammonium bromide─at two different concentrations, each to examine the effect of surfactant type. Additionally, the interfacial tension (IFT) between crude oil and different imbibition solutions is measured, and the contact angles of an oil droplet on the core surface in air, formation water, distilled water, and surfactant solution are determined. Finally, the effects of IFT, rock wettability, formation water salinity, and core permeability on final oil recovery by spontaneous imbibition are analyzed. The results indicate that surfactant-assisted spontaneous imbibition primarily operates through IFT reduction, wettability alteration, and emulsification of crude oil. However, ultralow IFT may lead to low ultimate oil recovery. To increase the ultimate oil recovery of spontaneous imbibition, reducing the salinity of the surfactant solution and creating microfractures can be effective strategies.

Using Sodium Dodecyl Sulfate (SDS) and CO2 as Environmentally Friendly Method for Reducing Residual Oil Saturation

Dioxide carbon is essentially blamed to be the main factors causing the climate change effect because it is the most important anthropogenic greenhouse gas. Carbon capture and storage (CCS) technology is widely embraced as one of the leading and easiest Environmentally Friendly ways of mitigating carbon emissions to the atmosphere. By reducing interfacial tension and enhancing oil mobility, surfactant flooding increases oil production by improving the displacement of the oil by water injection. When porous rocks’ wettability is improved with surfactant EOR, more oil is displaced from the water that passes through them more efficiently. One of the major problems with Enhanced Oil Recovery (EOR) operations is surfactant adsorption. The injection of surfactants into the field to reduce interfacial tension, modify wettability, and regulate mobility in order to increase the amount of oil recovered from a previously water-flooded reservoir is one method of enhanced oil recovery (the extraction of previously unattainable petroleum from an oil deposit using non-traditional methods). The loss of surfactant resulting from adsorption on formation rocks is one of the process’ major challenges. In fact, significant surfactant adsorption can cause chemical EOR procedures uneconomical. After studying the phase behavior and the interfacial characteristics of 10 surfactants with oil, sodium dodecyl sulfate (SDS) was chosen as the surfactant. Since sodium dodecyl sulfate had a higher oil recovery rate than the other surfactants, it was chosen among those Furthermore, it can produce stable emulsions at low concentrations without the need of a co-surfactant or an alkaline agent, and it can also do so while maintaining ultra-low interfacial tension (IFT). Carbon dioxide injection is a safe way to reduce its concentration in the atmosphere.

Study Evaluates Surfactant EOR From Tight Carbonates

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209418, “Surfactant Enhanced Oil Recovery From Tight Carbonates: Core-Scale Experiments to Reservoir-Scale Modeling,” by Yue Shi, SPE, and Kishore Mohanty, SPE, The University of Texas at Austin. The paper has not been peer reviewed. _ Most carbonate reservoirs are oil-wet/mixed-wet and heterogeneous at multiple scales. The majority of the injected water flows through the high-permeability regions and fractures and bypasses the oil in the matrix because of high negative capillary pressure (Pc). To enhance oil recovery from such reservoirs, the sign of the Pc should be changed by wettability alteration (WA) or the Pc should be reduced by lowering interfacial tension (IFT). In the complete paper, surfactants that can either alter wettability or develop ultralow IFT were identified through laboratory measurements for the target carbonate reservoir. Introduction Contact-angle, IFT, phase-behavior, and imbibition tests were first performed, and surfactants that can either alter wettability or develop ultralow IFT were identified. Then, a laboratory-scale imbibition model was built with commercial reservoir simulation software. A sensitivity study was performed to evaluate the effects of residual oil saturation (Sor), alteration of Pc and relative permeability (Kr), IFT, and matrix scale on oil recovery by surfactant. Next, the laboratory-scale imbibition model was used to history match the experimental data and parameters were tuned for reservoir-scale simulation. Finally, a 3D layered field-scale model was developed to study the performance of the selected surfactants in injection/soak/production (ISP) tests. Materials Eight anionic surfactants (An 1 through An 8) and two quaternary ammonium cationic surfactants (Cat 1 and 2) were used. Silurian dolomite (SD) outcrop cores were used in this study. Fluid samples were obtained from a West Texas dolomite-rich reservoir. The oil has a density of 0.84 g/mL at 25°C and a viscosity of 7.46 cp at reservoir temperature (35°C). It has an acid number of 0.25 mg KOH/g and a base number of 1.0 mg KOH/g. The reservoir has been waterflooded for years, and total dissolved solids of brine has decreased from 112,668 to 40,393 ppm for recent produced water (PW). The authors detail the methodology for aqueous-stability, contact-angle-measurement, IFT-measurement, phase-behavior, and spontaneous-imbibition tests in the complete paper.

Oil Recovery Performance by Surfactant Flooding: A Perspective on Multiscale Evaluation Methods

Chemical-enhanced oil recovery (cEOR) is a class of techniques commonly used to extract hydrocarbon fluids from reservoir rocks beyond conventional waterflooding. Surfactants are among the chemical agents employed in a cEOR process, as they aid in enhancing oil recovery by lowering the oil–water interfacial tension (IFT) and altering the rock wettability toward less oil-wet conditions. Understanding the flow characteristics and mechanisms involved during surfactant flooding helps improve the performance of injected surfactants and results in higher oil recovery. The objective of this review is to outline the recent applications of the different methods employed to understand the behavior and mechanisms involved during surfactant-enhanced oil recovery. The review begins with a general background highlighting the basic characteristics of surfactants and the main mechanisms by which they exert their influence. Recent studies conducted to investigate the oil recovery performance through different methods are then presented, including traditional coreflooding experiments, microfluidics studies, and oil recovery through sand packs. The methodology of the analysis and the interpretation of the data obtained from the different oil recovery tests, including oil recovery factor, pressure data, and relative permeability, are also described. Pore-scale analysis and imaging methods including nuclear magnetic resonance (NMR), magnetic resonance imaging (MRI), and X-ray medical and microcomputed tomography (μCT) scanning and their applicability in assessing the recovery performance are described. Finally, a few examples of field monitoring methods for surfactant flooding are highlighted. This review provides knowledge of the different multiscale evaluation methods and their applicability during surfactant flooding.

Experimental study on the evaluation of surfactant/polymer flooding for enhancing oil recovery in Kumkol Oil Field

Chemical enhanced oil recovery (EOR) methods are shown to sweep the residual oil by altering physical properties of fluids after waterflooding to improve oil recovery. This work presents an experimental study on the surfactant/polymer injection for EOR in sandstone reservoirs. Interfacial tension measurements, emulsification and rheology tests are performed to select the best candidates from thirteen commercial surfactants and five commercial polymers. The performance of the preferred surfactant and polymer candidates in EOR is evaluated through a series of core flooding experiments on both homogeneous and heterogenous sand packs. Different injection schemes are investigated. The results show that the polymer injection and polymer-surfactant-mixture slug can effectively displace the residual oil as the polymer injection improves efficiency of the sweeping front. Core flooding experiments on the heterogenous sand pack show that injecting polymer in the first, followed by surfactant slug yields the better performance compared with combined polymer-surfactant-mixture injection as the polymer pre-flush improves the vertical conformance of the surfactant solution and the final recovery.

Improvement of oil recovery factor in tight reservoirs: A laboratory approach based on carbon dioxide enhanced oil recovery methods

Production from unconventional oil reservoirs has always been a critical issue for the oil industry. In this regard, we implemented a set of experimental scenarios containing CO2/N2 cyclic injection, the foams generated by nitrogen and carbon dioxide, cyclic carbon dioxide injection, and a combined effect of carbon dioxide and surfactant enhanced oil recovery methods. As water injection has reached a plateau around two pore volume injection, we continued the tests from two pore volume injection for different scenarios. It was observed that CO2/N2-foam has the highest oil recovery factor of 34.9%; however, CO2-foam, regarding more feasibility than N2, witnessed the highest oil recovery factor after CO2/N2-foam. On the other hand, the incremental oil recovery factor for surfactant flooding, carbonated water flooding, and carbonated water with surfactant flooding is measured at 4.9, 8.5, and 10.6%, respectively.

Enhanced oil recovery with nanofluids based on aluminum oxide and 1-dodecyl-3-methylimidazolium chloride ionic liquid

Surface-active ionic liquids (SAILs) have multiplied the possibilities of surfactant enhanced oil recovery (EOR) methods. Among their multiple promising features, the possibility of functionalization and their stability at harsh conditions should be highlighted for the application. They have been successfully applied to increase oil recovery by improving crucial parameters such as: formulation stability, reduction of water–oil interfacial tension, and wettability. Recently, nanoparticles have attracted attention for EOR applications due to their capacity to modify the properties of rock surfaces. However, to date no research has been conducted on the combination of SAILs with nanoparticles for EOR. In this work, the combination of the SAIL 1-dodecyl-3-methylimidazolium chloride, [C12mim]Cl, with Al2O3 nanoparticles is proposed for EOR. Stable dispersions in brine were achieved, using the polymer polyvinylpyrrolidone (PVP) as a stabilizing agent, and characterized through density and dynamic viscosity measurements. According to stability and interfacial tension studies, a nanofluid consisting of 0.05 wt% [C12mim]Cl, 0.05 wt% Al2O3 and 1.0 wt% PVP, in brine (5.0 wt% NaCl) was proposed for EOR in carbonate reservoirs. The presence of nanoparticles reduced the adsorption of the surfactant-polymer formulation on carbonate rocks and changed the aged rock wettability from oil-wet to water-wet. An additional oil recovery of 10.4 %OOIP was achieved with the surfactant-polymer formulation, in comparison with 14.8 %OOIP obtained with the nanofluid.

Experimental investigation of N-lauroyl sarcosine and N-lauroyl-L-glutamic acid as green surfactants for enhanced oil recovery application

The vast deployment of surfactants worldwide in various industries has an intense impact on the environment. This led to the quest for surfactants with high performance but less environmental footprint. Therefore, bio-based surfactants derived from renewable sources have evolved as greener alternatives to conventionally deployed surfactants. Amino acid-based surfactants (AAS) prove to be a promising class of biodegradable and biocompatible surfactants with better safety profiles that meet both physiological and ecological requirements. Nevertheless, they are yet to be deployed in enhanced oil recovery (EOR) application due to limited investigation into their EOR potential. Owing to the recent report on the satisfactory performance of sodium cocoyl alaninate in terms of its EOR potential, this current study investigates the EOR potential of N-lauroyl sarcosine (NLS) and lauroyl glutamic acid (LGA). The study encompasses their surface and aggregation behavior, interfacial tension reduction and wettability alteration capability, emulsification, adsorption behaviour and oil displacement test. NLS proved to be more surface-active than LGA due to the additional carboxylate in the head group of LGA. Both surfactants showed high tolerance to salt and hardness, especially at high-temperature conditions. Furthermore, NLS showed superior IFT reduction capability with a minimum IFT of 0.07 mN/m while LGA only attained a minimum IFT of 0.14 mN/m. This results in better emulsifying power of NLS, yet LGA yielded more stable emulsions. In agreement to their high salt tolerance both surfactants exhibited improved performance in IFT reduction at high salinity condition. NLS and LGA also showed good wetting power on the quartz surface, hence altering rock surface wettability. Both surfactants achieved significant oil recovery after waterflooding, with NLS attaining additional oil recovery of 43% and LGA attaining 25%. The optimistic recoveries are due to the low waterflood recovery. NLS and LGA, therefore, prove to be superb alternatives to conventionally deployed EOR surfactants due to satisfactory performances coupled with their environmentally benign nature.

Evaluation the role of natural surfactants from Tanacetum and Tarragon plants in EOR applications

Nowadays, the plant extracts, as natural surfactants, are considered as part of the enhanced oil recovery (EOR) methods due to their high performance in reducing the interfacial tension (IFT) and environmentally friendly manner. Hence, this study focuses on the application of two new natural surfactants in EOR, which were extracted from Tanacetum (TAN) and Tarragon (TAR) plants. The critical micelle concentration (CMC) of the prepared natural surfactants was determined using the conductivity and IFT measurements to identify where surfactant molecules are in the bulk phase and far from the aggregation. Several measurements of IFT and contact angle (CA) of the fluid/fluid and fluid/fluid/rock systems were carried out with the presence of the prepared natural surfactants at concentrations of 500, 1000, 2000, 3000, 4000, 5000, 6000 and 7000 ppm within the distilled water (DW) and brine. The obtained results of IFT showed that it was reduced from 29.5 and 28 to 5.12 and 6.57 mN/m when 5000 ppm and 1000 ppm of Tarragon added into DW and brine, respectively. While, the IFT was reduced to 2.09 and 1.87 mN/m with the presence of DW-TAN7000 and brine-TAN1000 surfactant solutions, respectively. Additionally, the minimum CAs of 30.8° and 33° of the oil droplets on the surface of the carbonate rock were measured with the presence of the DW based TAR5000 and TAN1000, respectively. Ultimately, the results of the oil displacements using the carbonate core plugs illustrated 11.7% and 13.2% increases in the recovery factor using TAR1000 and TAN1000 solutions.

In situ micro-emulsification during surfactant enhanced oil recovery: A microfluidic study

HypothesisIt is generally believed that the improved efficiency of surfactant enhanced oil recovery (EOR) comes from ultra-low interfacial tension (IFT) between oil and surfactant solution owing to the formation of middle-phase microemulsion. However, hindered visibility in underground porous media prevents direct observation of in situ generation of middle-phase microemulsion during surfactant flooding. Thus, direct visualization of the process is vital, and could clarify its contribution to EOR. ExperimentsMicro-emulsification of a displacing fluid containing sodium 4-dodecylbenzenesulfonate and alcohol propoxy sulfate with model oil was investigated. Phase diagrams were drawn using salinity scans, and the influence of polymer on emulsification was analyzed. Micro-emulsification was monitored through in situ fluorescent tagging via 2D-microfluidics and ex situ visualization via cryo-electron microscopy and small angle X-ray scattering. Its contribution to the oil recovery factor was quantified by measuring the volume of each phase in the eluates. FindingsOn-chip experiments indicated that in situ micro-emulsification occurred when the prescreened surfactant solution flowed in contact with trapped oil. The aqueous phase initially invaded the residual oil, forming a low mobility microemulsion. This microemulsion was then diluted by subsequent displacing fluid, forming a new driving fluid that caused ultra-low IFT in the trapped oil downstream. Under the synergistic effect of micellar solubilization and trapped-oil mobilization, the recovery factor could be increased by up to 40% over waterflooding and 43% on polymer inclusion in the formulation.

New insights into the mechanism of surfactant enhanced oil recovery: Micellar solubilization and in-situ emulsification

Reducing the oil-water interfacial tension (IFT) to ultra-low is believed the primary mechanism for surfactant-based enhanced oil recovery (EOR) process. However, field trials have shown that low concentration surfactant flooding can also improve oil recovery without ultra-low IFT. To clarify the mechanism behind, the currently-used surfactant, naphthenic arylsulfonate (NAS), was used to unravel its function during surfactant flooding from the horizon of micron- and nano-scale. The solubilization capacity of NAS micelle to petroleum fractions was evaluated through light absorbance strategy, small-angle neutron scattering, dynamic light scattering and transmission electron microscopy. It was found that micellar solubilization plays a significant role during the surfactant flooding. In-situ emulsification was visualized in microfluidics with three types of microchips, respectively. A series of displacement tests were carried out with NAS solution pumping into oil-saturated chip. The results show that in-situ emulsification improve oil recovery mainly through blocking and entrainment effects. Results from this work aid in understanding the interaction between surfactant solution and petroleum fractions at low surfactant concentration, which is helpful for design surfactant-based displacing system for EOR process.

Investigation of the enhanced oil recovery potential of sodium cocoyl alaninate: an eco-friendly surfactant

Amino acid-based surfactants (AASs) and other novel surfactants have recently gained attention to provide a favorable environmental image (“green”) in surfactant application. Yet their potential in enhancing oil recovery is not well investigated. Only a few works have been reported on their potential enhanced oil recovery (EOR) application with less satisfactory results. Here in, sodium cocoyl alaninate (SCA), an acylated amino acid with excellent properties that facilitate its application in other fields, is investigated for its EOR potential. Its effectiveness in lowering the interfacial tension and the emulsifying crude oil–brine mixture were studied. The ability to alter rock surface wettability and its adsorption behavior on the sand surface were studied as well. Then, its oil recovery potential was confirmed through a core displacement experiment. All studies were performed in comparison with conventionally deployed sodium dodecyl sulfate (SDS). The critical micelle concentrations for SCA (CMC = 0.23 wt%) and SDS (CMC = 0.21 wt%) were close, which serves as a good basis for comparing their EOR potential. SCA proved to be more effective in IFT reduction attaining a minimum IFT of 0.069 mN/m (i.e., ~ 98.8% IFT reduction) compared to 0.222 mN/m of SDS (i.e., ~ 96.2% IFT reduction) at the same concentration. Salinity showed a synergistic effect on the interfacial properties of both SCA and SDS but had a more significant impact on SDS interfacial properties than SCA due to low salt tolerance of SDS. The low IFT attained by SCA yielded enhanced emulsion formation and stable emulsion both at 25 °C and 80 °C for a period of one week. SCA also altered quartz surface wettability better via reduction of contact angle by 94.55% compared to SDS with contact angle reduction of 87.51%. The adsorption data were analyzed with the aid of various adsorption isotherm models. The adsorption behavior of SCA and SDS could be best described by the Langmuir model. This means a monomolecular surfactant layer exists at the aqueous–rock interface. SDS also exhibited more severe adsorption on the sand surface with the maximum adsorption density of 15.94 mg/g compared to SCA with the maximum adsorption density of 13.64 mg/g. The core flood data also confirmed that SCA has a better oil recovery potential than SDS with an additional oil recovery of 29.53% compared to 23.83% of SDS. This additional oil recovery was very satisfactory compared to the performance of other AAS that have been studied. This study therefore proves that SCA and other AAS could be outstanding alternatives to conventional EOR surfactants owing to their excellent EOR potential in addition to their environmental benign nature.

Enhancement of oil recovery by surfactant-polymer synergy flooding: A review

With the depletion of conventional resources, it is necessary to enhance the recovery of remaining oil. The tertiary oil recovery chemical flooding is the most promising for enhanced oil recovery (EOR). The use of alkali in chemical flooding produces fouling with the formation, which brings new challenges to chemical flooding EOR. So, alkali-free surfactant-polymer (SP) flooding is used as a new solution for EOR. The polymer makes the displacing fluid have a high viscosity and increases the swept volume. The surfactant can decrease the interfacial tension and emulsify the crude oil while the displacing fluid reaches the corresponding area. The synergistic effect of the two is more conducive to the recovery of the remaining oil. As a result, SP flooding is a more practical approach to enhance oilfield EOR. The research status of several surfactant and polymer types for EOR is reported in this work. According to the study, complex and anionic surfactants are better for EOR. For difficult formations, SP flooding is more suited because of the presence of polymers. Additionally, study analysis demonstrates that SP flooding and alternative polymer injection, when employed at the same cost, can enhance EOR and assist in resolving issues brought on by low oil prices.

SARA-Based Correlation To Describe the Effect of Polar/Nonpolar Interaction, Salinity, and Temperature for Interfacial Tension of Low-Asphaltene Crude Oils Characteristic of Unconventional Shale Reservoirs

Summary Oil/water interfacial tension (IFT) is an important parameter in petroleum engineering, especially for enhanced-oil-recovery (EOR) techniques. Surfactant and low-salinity EOR target IFT reduction to improve oil recovery. IFT values can be determined by empirical correlation, but widely used thermodynamic-based correlations do not account for the surface-activities characteristic of the polar/nonpolar interactions caused by naturally existing components in the crude oil. In addition, most crude oils included in these correlations come from conventional reservoirs, which are often dissimilar to the low-asphaltene crude oils produced from shale reservoirs. This study presents a novel oil-composition-based IFT correlation that can be applied to shale-crude-oil samples. The correlation is dependent on the saturates/aromatics/resins/asphaltenes (SARA) analysis of the oil samples. We show that the crude oil produced from most unconventional reservoirs contains little to no asphaltic material. In addition, a more thorough investigation of the effect of oil components, salinity, temperature, and their interactions on the oil/water IFT is provided and explained using the mutual polarity/solubility concept. Fifteen crude-oil samples from prominent US shale plays (i.e., Eagle Ford, Middle Bakken, and Wolfcamp) are included in this study. IFT was measured in systems with salinity from 0 to 24% and temperatures up to 195°F.

Screening of imbibition surfactant in inter-salt shale reservoir

Under the current environment of low oil price, surfactant enhanced oil recovery technology is more economic and feasible without changing fracturing technology and adding special equipment. Surfactant enhanced oil recovery is induced by decreasing interfacial tension and changing wettability. However, there are many kinds of surfactant, and the reservoir conditions and rock types are different, so the first requirement of enhanced oil recovery is to select the surfactant which is suitable for the target reservoir. In view of the characteristics of high temperature and high salinity in inter-salt shale reservoir, in this paper, several surfactant types were selected and negative/non-composite surfactants were screened out by taking the adhesion work reduction factor related to imbibition resistance as the main index. This study is of practical significance for hydraulic fracturing reservoirs with surfactant enhanced oil recovery technology.

Development of Ultralow Interfacial Tension Lignosulfonate from Kraft Black Liquor for Enhanced Oil Recovery

Indonesia aims to implement large-scale enhanced oil recovery (EOR) to increase the national oil production. Chemical EOR is a promising technology to boost the production of old reservoirs with the aid of surfactants and polymers. Thus, the production of low-cost EOR surfactants from local resources with acceptable performance is highly attractive. The objective of the present work was to demonstrate the development of low-cost lignosulfonate surfactant production from kraft black liquor (BL). First, lignin was isolated from black liquor using a novel CO2 bubbling technique, followed by addition of coagulants. Next, sodium lignosulfonate (SLS) was synthesized from the resulting lignin, followed by formulation of SLS with octanol and palm fatty acid distillate (PFAD) soap to obtain an ultralow interfacial tension (IFT) surfactant. The initial IFT value of the SLS solution was already high at 0.7 mN/m. After formulation, the composition SLS:PFAD soap:octanol = 70:22:8 (wt%) improved the IFT value to 3.1 10-3 mN/m. An ultralow IFT in the range of 10-3 mN/m as achieved here fulfills the required IFT value for EOR surfactant.