Surfactant Injection Research Articles

Simultaneous use of disulphide oil for chemical‐enhanced oil recovery by emulsion formation and stability with asphaltene deposition control

AbstractDisulphide oil (DSO) is a by‐product of oil and gas refining processes that is generated during the removal of mercaptans and the sweetening of light hydrocarbons. Asphalt deposition, especially asphaltene deposition during enhanced oil recovery methods, reduces oil recovery from the reservoir, so the use of a substance such as DSO, which has the ability to control and reduce asphaltene deposition, can be effective in increasing oil recovery from the reservoir. In this research, a micromodel with a fracture design and a matrix that represents fracture reservoirs was utilized. These tests were conducted in two groups. The first group of tests is related to adding DSO to crude oil and using 70 to 30 vol.% oil–water emulsion containing salt, surfactant, and nanoparticles. The second group involved adding DSO to both crude oil and emulsion. The first group aimed at stimulation and the second group aimed at chemical enhanced oil recovery (C‐EOR). The formation and stability of water‐in‐oil emulsion was done by analyzing the average droplet size. As a result, in the first group of tests with the presence of DSO in the oil, by measuring the average diameter before and after injection of AOS surfactant, it was observed that the average droplet size decreased from 6.89 to 4.01 μm, which indicates an increase in the emulsion stability. In the second group, where DSO was present in both oil and water emulsion in injected oil, it can be seen that the average diameter of the droplets in the surfactant decreased from 5.12 to 3.21 μm.

Enhancing exemestane delivery: Solid lipid nanoparticles formulation and pharmacokinetic evaluation

This research investigates the development of exemestane (EXM) solid lipid nanoparticles (SLNs) for the purpose of improving drug delivery. To prepare EXM SLNs, glycerol monostearate was used as the lipid and Tween 80 as the surfactant and solvent injection followed by high-pressure homogenization as a method of preparation. The formulation parameters were optimized, leading to the development of a promising formula. The formula has a particle size of 188.72 ± 5.62 nm, a polydispersity index (PDI) of 0.215 ± 0.023, and an %EE of 65.39 ± 2.54 %. The formulation's robustness was indicated by minimal changes in particle size and %EE over 30 days, as revealed by stability studies. The bioavailability of EXM SLNs was found to be significantly improved in Wistar rats compared to conventional EXM suspension, as shown by pharmacokinetic studies. The formula that was optimized showed a higher maximum plasma concentration (Cmax) of 168.92 ± 2.40 ng/mL, a delayed time to reach Cmax (Tmax) of 4 hours, and significantly higher area under the curve (AUC) values. These results highlight the effectiveness of the optimized formula in improving drug absorption and bioavailability. The findings indicate that EXM SLNs show potential for enhancing the delivery and effectiveness of EXM, specifically in the treatment of breast cancer.

Synthesis of hydrophobic polymeric surfactant (Polyacrylamide/Zwitterionic) and its effect on enhanced oil recovery (EOR)

Injection of surfactant and polymer at the same time is one of the challenges that reduce their performance in reservoirs. Using a polymeric surfactant (PS) as a single new material can be the best alternative to solve the existing challenges. Considering the basic problems of chemical injection, this work focuses on the surface adsorption of polymer/surfactant on carbonate reservoirs (CRs). In this work, polyacrylamide was synthesized using zwitterionic as a hydrophobic polymeric surfactant (i.e. HZPAA). For a better comparison, this substance was compared with hydrolyzed polyacrylamide (HPAA) in concentrations of 40 to 1000 mg in CRs. Examining the results states that with increasing polymer concentration, the surface absorption of HZPAA and HPAA on dolomite reservoir rocks (DRRs) with positive surface charge increases. The attendance of COO and SO3− functional groups in the matrix of the new polymer (i.e. HZPAA) creates electrostatic forces and superior surface absorption. Their mechanism works in such a way that negative functional groups attract positively charged surfaces and increase the surface absorption of the polymer. Investigations show that the new synthesized material (i.e. HZPAA) can provide a new approach to improving surface absorption in carbonate reservoirs.

Enhancing Oil Recovery in Eagle Ford Shale: A Multiscale Simulation Study of Surfactant Huff ’n’ Puff Methodology

In this paper, we present a simulation case study of a surfactant huff ’n’ puff pilot in the black oil window of the Eagle Ford (EF) Shale. The target horizontal well, which had been depleted for nearly 8 years, underwent stimulation via a surfactant huff ’n’ puff treatment. The surfactant was selected through laboratory screening using reservoir rock and fluid samples. After a 17-hour injection and a 1-month shut-in period, the well’s production increased fivefold from the baseline oil rate, sustaining incremental oil production for at least 2 years. The surfactant enhances oil recovery by altering rock wettability toward a more water-wet state and moderating oil/water interfacial tension (IFT). This process is modeled by surfactant adsorption in the simulator, indicating the degree of dynamic changes in relative permeability (krl) and capillary pressure (Pc) curves. We propose a comprehensive workflow comprising three stages: development of core-scale and field-scale models, sequential model calibrations, and multiobjective optimization to integrate laboratory measurements and field data from this pilot into multiscale numerical simulations. By matching oil recoveries from imbibition experiments on the core model and field production histories on the field model, krl and Pc profiles of two extreme states, basic reservoir properties, and additional reservoir properties altered during huff ’n’ puff operations are characterized. The matched core model reproduces a 15.1% incremental oil recovery for surfactant-assisted spontaneous imbibition (SASI) process relative to pure brine imbibition process. The matched reservoir model predicts the surfactant huff ’n’ puff treatment increases the oil production by 21.9% relative to water huff ’n’ puff treatment and by 52.9% relative to primary depletion for a 4-year period. The calibrated reservoir model also serves as a base case for optimizing well operation schedules through the implementation of a multiobjective genetic algorithm. The surfactant injection rate, injection time, and well shut-in time of the base case are varied to achieve higher oil production and reduced surfactant usage. Statistical analysis of eight trade-off cases indicates that optimal well operations, compared with existing practices, frequently involve increased injection rates [16.6–18.9 barrels per minute (bpm)], shorter injection periods (10–11.3 hours), and prolonged shut-indurations (49–65 days). This workflow offers valuable insights into surfactant huff ’n’ puff treatments for unconventional reservoirs, thereby facilitating the optimization of well operations and maximizing tertiary oil recovery.

The Effect of Alpha Olefin Sulphonate (AOS) Surfactant Injection on Sandstone Rock on Increasing Oil Recovery with Variations in Salinity, Concentration, and Temperatures: A Laboratory Study

In this study, Alpha Olefin Sulphonate (AOS) surfactant was injected. This laboratory test aims to verify the correlation between a surfactant solution’s low IFT value and its ability to yield a high oil recovery value. The salinity used in this research was 5000 ppm and 15000 ppm. Then it was mixed with AOS surfactant at concentrations of 0.5%, 1%, and 2%. At the same time, the temperatures used are 30 °C and 60 °C. After testing, it was found that a solution with a salinity of 15,000 ppm and a surfactant concentration of 2% had the lowest IFT value and was proven to have a total RF of 73%.

Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection

Improved and efficient recovery methods are investigated as possible candidates to arrest the production decline and to improve the injection capacity in hydrocarbon fields in Lithuania. The data show that the Cambrian reservoirs in Lithuania are mixed to oil-wet in nature, which results in poor water-flooding efficiency. Wettability alteration could help in improved water injection and, at the same time, it could help recover additional oil from the residual oil saturation zone of the reservoir. In this paper, a screening exercise is conducted to help alter reservoir wettability, improve water injection efficiency, and to improve oil recovery. Analytical and machine-learning supported methods are used for screening. Based on the screening results, dilute surfactant-based injection techniques are suggested as a potential method to improve injectivity and, thereby, recovery from the field. An initial experimental analysis targets the wettability of the rock from the field, followed by testing for wettability-altering surfactants. Based on the findings of the screening study and experimental analysis, it is recommended that we initiate a core flooding experimental program to investigate wettability changes and enhance injection and recovery from the field.

Investigating the foaming behavior of a soybean derived surfactant for gas well deliquification in a sparger setup

Surfactant injection is one of the common gas-well deliquification techniques to enhance gas productivity. However, most traditional chemical-based surfactants are often nonbiodegradable, toxic, and lead to environmental and potential health risks. There is a need to investigate surfactants of natural origins, soybean derived surfactants (SODS) offer promising eco-friendly alternatives. It is crucial to understand the foaming behavior of the biosurfactant and its effectiveness in the deliquification process. Therefore, the main objective of this study is to carry out a comprehensive analysis of the foaming characteristics of SODS and correlate its dynamic surface tension to the foaming properties of other known surfactant solutions using a sparger setup.The results showed that the SODS can generate stable foams and have the potential to mitigate liquid loading problems in gas wells. The bubble formation at the tip of the sparger is highly dependent on the bubble size and foam drainage, so, the surface tension reduction rate (R1/2) is inversely proportional to the bubble radius (R‾) for all the surfactants under study. Consequently, the total foam weight and foam density of SODS are determined at the top of the production column of the experimental setup, hence the liquid content of the foam (∅l) determines the foam formation for the biosurfactant. Also, the foaming qualities in terms of foamability and foam stability increase with maximum R1/2 for the all the surfactants used. The sparger configuration agrees with the Ross-Miles test for ∅l and R1/2 with the R2 value of 0.91. The study offers a novel strategy for effective gas well deliquification using surfactants with natural origins, furthering sustainable practices in the oil and gas production sector.

Vertical displacement of a non-Newtonian Bingham plastic by a Newtonian phase in an axially composite reservoir

In general, oil reservoirs may consist of composite sedimentary structures composed of materials such as sand, clay, or limestone, which exhibit varying lithology due to sedimentary processes. A comprehensive knowledge of this lithology is essential for accurately assessing their hydrocarbon storage and production capacity. Additionally, this information is indispensable for the implementation of various recovery techniques such as waterflooding, gas injection, surfactant injection, polymer injection, alkaline water solution injection, and others. Highly viscous oil can exhibit non-Newtonian behavior during water injection in certain cases. The use of surfactants, alkaline, or polymer solutions in enhanced oil recovery also introduces non-Newtonian behavior. Recovery methods face challenges when non-Newtonian phases, gravity, and reservoir heterogeneity are combined. Against this backdrop, this work presents a mathematical model for immiscible two-phase flow in an axially composite reservoir with a periodic-layered structure. The model considers a non-Newtonian plastic Bingham-type phase extension of the Buckley-Leverett model. To address the porous medium’s heterogeneity with discontinuous flux functions, the numerical solutions were obtained using the Lax-Friedrichs and Lagrangian-Eulerian schemes. The numerical solutions were compared to analytical solutions obtained using an extended version of Oleinik’s geometric construction for discontinuous flux functions. The outcomes display shock and rarefaction waves, as well as a fixed shock due to the porous medium heterogeneity. The numerical results closely correspond with the analytical solutions, seen particularly in the greater accuracy of the Lagrangian-Eulerian method compared to the Lax-Friedrichs method.

A review of scale inhibitor methods during modified smart water injection

AbstractEnhancing oil recovery (EOR) through water flooding methods, including smart water injection, low salinity water injection, polymer injection, and surfactant injection has become a pivotal strategy for enhancing productivity. Despite their promising outcomes, these methods often encounter challenges such as scaling formation and deposition, impacting reservoir permeability and production rates. A comprehensive understanding of scaling formation is crucial for effective implementation of these methods. This article explores various scaling types prevalent in the field, examining key parameters (temperature, pressure, and pH) that influence scaling formation. Additionally, it presents a diverse range of inhibitors employing both chemical and mechanical methods to mitigate and prevent scaling, thus safeguarding reservoir performance. The efficiency of inhibitors is scrutinized concerning chemical composition and performance maintenance under different temperature and pressure conditions. This study serves as a valuable resource for researchers, engineers, and industry experts involved in the oil industry and reservoir management. By elucidating scaling mechanisms, delineating consequences, and offering extensive solutions, it enhances comprehension and provides a foundation for improving oil recovery strategies. The findings of this study contribute to a better understanding of scaling mechanisms, providing insights that can be applied to optimize oil recovery processes, mitigate reservoir challenges, and improve overall reservoir management strategies.

Application of Natural Surfactant from Morus alba, Soapnut, Sapindus rarak for Enhanced Oil Recovery – Critical Review

This literature discusses the importance of green surfactants in the oil and gas industry as one of the injection types in EOR. The use of green surfactants is good for protecting the environment and marine biodiversity from conventional chemical surfactants. The injection of green surfactants uses natural materials from Soapnut, Mulberry, and Sapindus rarak. These three types of plants are abundant in Indonesia and contain saponin as a material in making good surfactants. Saponin is an amphipathic glycoside that can produce foam when shaken vigorously in a solution. The foam produced by saponin can increase the sweep efficiency in oil wells to increase production. The writing method used in this article is based on scientific literature that discusses the characteristics and physical properties of Soapnut, Mulberry, and Sapindus rarak. The IFT calculation for Soapnut between water and oil reduced from 19 dyne/cm to 2.5 dyne/cm as the surfactant concentration increased from 0 to 12 (w/w%). Mulberry from 43.9 to 17.9 dyne/cm and Sapindus rarak from 3.07 mN/m to 0.96. These natural surfactants enhance water flooding efficiency by 19.6% OOIP, reduces shale contact angle from 52.44 to 19.66, emphasizing natural surfactants oil recovery potential with environmental benefits.

The effect of fir wood SLS surfactant concentration on the characteristics of light crude oil

As time progresses, oil production will gradually depletes considering limited oil reserves. This is why, an advanced stage method known as tertiary oil recovery is required. One of these methods is known as Enhanced Oil Recovery method. In this laboratory study, one specific surfactant fluid was used, namely Fir wood sodium lignosulfonate (SLS) with varying concentrations of 0.50; 1.00; 1.50; 2.00; 2.50; and 3.00% each crude oil 39 ° API. This study aims to witness the stability of SLS surfactant fluid in chemical injection. SLS surfactant injection is carried out to increase oil production in the reservoir. In this study, there are various stages in order to test the characteristics of the SLS surfactant, so it can be declared as effective in oil sweeping, namely phase behaviour test, density testing, phase behaviour test, interfacial tension test, and adsorption test. Density test is carried out to determine the density of a fluid. Phase behaviour test is intended to see the stability of emulsion obtained from the utilization of SLS surfactant. The main objective of surfactant utilization is to reduce interfacial tension which leads to IFT test. The IFT (interfacial tension) results of the SLS surfactant fluid are determined from the results of the stable phase behaviour test which evidently shows the critical micelle concentration (CMC) point, so it can properly reduce the interfacial tension of oil and formation water in the reservoir. Interfacial tension test was carried out to determine the interfacial tension between SLS surfactant and oil. Adsorption test is carried out to witness the level of fluid adsorption onto the rock surface. On static adsorption test, the result showed for 2 % surfactant concentration is 9.526 mg/gr. Dynamic adsorption test was conducted on the same concentration show results of respectively 1.865 mg/gr.

An Experimental Investigation into the Role of an In Situ Microemulsion for Enhancing Oil Recovery in Tight Formations

Surfactant huff-n-puff (HnP) has been shown to be an effective protocol to improve oil recovery in tight and ultratight reservoirs. The success of surfactant HnP for enhanced oil recovery (EOR) process depends on the efficiency of the designed chemical formula, as the formation of an in situ microemulsion by surfactant injection is considered to be the most desirable condition for achieving an ultra-low interfacial tension during the HnP process. In this work, we conducted experimental studies on the mechanism of in situ microemulsion EOR in the Mahu tight oil reservoir. Salinity scan experiments were carried out to compare different surfactants with crude oil from the Mahu reservoir, starting with the assessment of surfactant micellar solutions for their ability to form microemulsions with Mahu crude oil and examining the interfacial characteristics. Subsequently, detailed micromodels representing millimeter-scale fractures, micron-scale pores, and nano-scale channels were utilized to study the imbibition and flowback of various surfactant micellar solutions. Observations of the in situ microemulsion system revealed the mechanisms behind the enhanced oil recovery, which was the emulsification’s near-miscibility effect leading to microemulsion formation and its performance under low-interfacial-tension conditions. During the injection process, notable improvements in the micro-scale pore throat heterogeneity were observed, which improved the pore fluid mobility. The flowback phase improved the channeling between the different media, promoting a uniform movement of the oil–water interface and aiding in the recovery of a significant amount of the oil phase permeability.

Impact of different angles of pulmonary surfactant administration on bronchopulmonaryplasia and intracranial hemorrhage in preterm infants: a prospective randomized controlled study

To investigate the effects of different angles of pulmonary surfactant (PS) administration on the incidence of bronchopulmonary dysplasia and intracranial hemorrhage in preterm infants. A prospective study was conducted on 146 preterm infants (gestational age <32 weeks) admitted to the Department of Neonatology, Provincial Hospital Affiliated to Anhui Medical University from January 2019 to May 2023. The infants were randomly assigned to different angles for injection of pulmonary surfactant groups: 0° group (34 cases), 30° group (36 cases), 45° group (38 cases), and 60° group (38 cases). Clinical indicators and outcomes were compared among the groups. The oxygenation index was lower in the 60° group compared with the other three groups, with shorter invasive ventilation time and oxygen use time, and a lower incidence of bronchopulmonary dysplasia than the other three groups (P<0.05). The incidence of intracranial hemorrhage was lower in the 60° group compared to the 0° group (P<0.05). The cure rate in the 60° group was higher than that in the 0° group and the 30° group (P<0.05). The clinical efficacy of injection of pulmonary surfactant at a 60° angle is higher than other angles, reducing the incidence of intracranial hemorrhage and bronchopulmonary dysplasia in preterm infants.

Experimental investigation of the impact of soybean oil-derived surfactant as a surface-active agent during gas well deliquification

The inability of the gas rate to overcome the gas critical (minimum) flow rate leads to liquid loading in a gas well. To avoid premature well shut-in, the injection of surfactants is one of the standard methods used in gas well deliquification, although many commercial surfactants pose environmental toxicity concerns. This project investigates the suitability of biosurfactants in generating foam that will reduce the surface tension of the liquid by adsorbing at the liquid-gas interface to create a more significant mass than the liquid droplets which can be easily extracted from the walls of the wellbore. An experimental setup simulating gas well conditions introduce a surfactant derived from soybean oil, subjecting it to tests for foam stability, unloading efficiency, and dynamic surface tension. The results from the modified ASTM D-892 test show that Soybean Oil Derived Surfactant (SODS) exhibits promising surface tension reduction properties and effectively alters the gas-liquid interface. With the increase in concentration from 200 ppm, 400 ppm, and 600 ppm, the expelled water increased from 17%, 28%, and 70% respectively. Similarly, Gao-Rosen adsorption isotherms confirmed SODS appropriate for the prediction of the adsorption from solution with the R2 values of approximately 1.0. This study introduces a cost-effective and environmentally friendly surfactant that performs favorably for gas well deliquification.

Numerical study of the mechanisms of nano-assisted foam flooding in porous media as an alternative to gas flooding

Oil reservoirs are nearing maturation, necessitating novel enhanced oil recovery (EOR) techniques to meet escalating global energy demands. This demand has spurred interest in reservoir production analysis and forecasting tools to enhance economic and technical efficiency. Accurate validation of these tools, known as simulators, using laboratory or field data is pivotal for precise reservoir productivity estimation. This study delves into the application of nanoparticles in foam flooding for mobility control to improve sweep efficiency. Foam generation can occur in-situ by simultaneous injection of surfactants and gas or through pre-generated foam injection into the reservoir. In this work, a series of systematic simulations were run to investigate how much injected fluids can reduce gas breakthrough while also increasing oil recovery. Subsequently, we analyzed the most effective optimization strategies, considering their economic limits. Our primary objective is to numerically model nanofoam flooding as an innovative EOR approach, synergizing foam flooding mechanisms with nanotechnology benefits. In this work, modeling of nanoparticles in foam liquid was represented by the interfacial properties provided to the injection fluid. Additionally, we simulated Water-Alternating-Gas (WAG) injection schemes across various cycles, comparing their outcomes. Our results showed that nanofoam injection achieved a higher recovery factor of at least 38% and 95% more than WAG and gas injections, respectively. The superior efficiency and productivity of foam injection compared to WAG and gas injection suggest an optimal EOR approach within the scope of our model. These simulated optimization techniques contribute to the future development of processes in this field.

Experimental and numerical modeling of a novel surfactant flooding: Core scale to reservoir models

This comprehensive study delves into an application of surfactant flooding as a robust enhanced oil recovery (EOR) technique, incorporating both core-scale experiments and reservoir-scale numerical simulations. The research's focal point is to evaluate a novel surfactant's performance in extending oil recovery efficiency within an oil reservoir. The study commences with thorough laboratory experiments at the core scale, illuminating the interplay of fluids within porous media. Transitioning seamlessly to reservoir-scale numerical modeling, the research replicates real-world reservoir conditions. Various well configurations are scrutinized to optimize surfactant flooding strategies for EOR purposes. A key aspect of this analysis is the in-depth examination of the sensitivity of numerical simulations to changes in relative permeability curves during surfactant injection, enabling a robust assessment of the performance of surfactant injection in a broad spectrum of uncertainties. Comparative experiments elucidated the significant influence of a surfactant molecular structure, with aliphatic variants showcasing superior oil displacement efficiency. Moreover, combining surfactant and polymer proved pivotal, enhancing reservoir sweep efficiency and significantly boosting oil recovery. This work establishes a comprehensive framework for evaluating chemical flooding, including surfactant and polymer, as a potent EOR method by bridging the gap between core-scale experiments and reservoir-scale simulations.

Microfluidic study of surfactant flooding of heavy oil in layered porous media containing fractures

AbstractSurfactant injection is a promising method for enhanced oil recovery (EOR) due to its effective micro‐displacement mechanisms. However, understanding the interaction of a surfactant solution with heavy oil in porous media is neither straightforward nor well understood, particularly in heterogeneous systems. By enabling in‐situ real‐time monitoring of flow transport, microfluidic studies have provided novel insights into the underlying multiphase physics of flow at the pore scale. This paper examines the two‐phase displacement efficiency of a new surfactant in layered–fractured porous microfluidic patterns, a topic seldom discussed in the literature. To evaluate the performance of the proposed surfactant, we considered several heterogeneous media with varying layer and fracture geometrical characteristics, quantifying displacement efficiency for each case. Based on the analysis of pore‐scale snapshots, it was inferred that the primary mechanisms responsible for EOR during surfactant flooding into heavy oil include pore wall transportation, emulsifications, the deformation of residual oil, inter‐pore or intra‐pore bridging, and wettability alteration. Macroscopic displacement experiments revealed that the width of the swept area from surfactant injection significantly exceeded that of water injection, resulting in a substantially higher oil recovery. Furthermore, it was demonstrated that the direction of fluid flow in relation to fracture orientation plays a critical role in the dynamics of surfactant solution movement and, consequently, the ultimate oil production.

Enhanced oil recovery potential analysis through simulation of a bio-based surfactant using CFD

Bio-based surfactant flooding is encouraged as an EORmethod, as it is obtained from natural sources and is economically attractive. In the present study, the EOR efficiency of a natural surfactant synthesized from rapseed oil has been simulated using ANSYS FLUENT. The process of oil recovery from a core by injection of surfactant has been simulated by incorporatingcore, brine, surfactant, and crude oil properties into the numerical model. Mass transfer of surfactant between the aqueous phase and crude oil has been modeled using species transport without a chemical reaction model. Species transport model has been coupled with the multiphase VOF model, where the flow of each phase is determined as per their respective viscous resistance. Experimental data of inletpressureand oil production has been used for history matchingand later used to visualize the oil flow through the porous media, concludingthat simulation of surfactant flooding can be achieved by species transport model.

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

Work Flow Screens Surfactants for EOR Through Wettability Alteration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3866246, “A Systematic Laboratory and Model-Based Surfactant Screening Work Flow for Enhanced Recovery Through Wettability Alteration in the Eagle Ford,” by Jason Jweda, SPE, Russ Bone, SPE, and Hesham El-Sobky, ConocoPhillips, et al. The paper has not been peer reviewed. _ Previous experimental studies and published field trials have shown that injected surfactants can be an effective means of improving recovery. Most experiments, however, have been conducted at ambient rather than reservoir conditions. The complete paper presents a novel approach to screen thermally stable surfactants at high pressures and high temperatures for the explicit purpose of wettability alteration in the operator’s Eagle Ford acreage. Early Internal Efforts Surfactant usage was initiated at the inception of the play. The use of these surfactants was discontinued after approximately 5 years of field development. Fieldwide performance analysis confirmed that off-the-shelf surfactants, on average, did not improve long-term performance statistically. Initial laboratory screening of bespoke surfactant chemistries commenced a few years later. To test surfactant properties near Eagle Ford reservoir conditions, a novel microfluidics experiment was conducted using synthetic microchips designed with reservoir specifications. Twenty-six flowback tests with Eagle Ford crude oil were conducted at 300°F and up to 3,800 psi with six different commercial surfactant chemistries. Imbibition results with the six commercial surfactants were compared with a control case with make-up brine water. Testing performed at 2 gal/thousand increased overall performance for the oil-wet conditions but decreased performance for mixed-wet conditions when compared with 1 gal/thousand. The surfactants tested in this series were temperature-dependent and had clogging tendencies of varying degrees within the microfluidics chips. Methods and Work Flow Promising results from the Amott cell imbibition and other experiments encouraged the authors to evaluate surfactants more holistically, with an emphasis on testing at Eagle Ford reservoir conditions. The first set of experiments involved fluid-stability tests, contact-angle measurements, interfacial-tension (IFT) measurements, static spontaneous-imbibition experiments, and completion-fluid-compatibility tests. An extensive set of commercially available surfactants was screened. The highest potential cationic and nonionic cosurfactant blends that passed through fluid stability, contact-angle, and static spontaneous-imbibition experiments were selected for hydraulic stimulation-fluid compatibility tests. After the compatibility tests, the two best-graded cationic and nonionic cosurfactant blends were used in a novel flowback experiment coupled with multistage nuclear magnetic resonance (NMR) measurements. Mechanistic reservoir simulation models were used to evaluate the production effect of wettability change caused by surfactant injection. The combination of laboratory-based experimentation and reservoir simulations provided strong confidence in holistically evaluating the potential of cosurfactant blends in the Eagle Ford.