Enhanced Oil Recovery Potential Research Articles

Implementation of a novel EOR screening methodology to the oilfields in Türkiye

In response to growing energy demand of Türkiye, an enhanced oil recovery (EOR) applicability assessment was conducted through an improved screening methodology, calibrated with successful applications. The methodology incorporated some improvements in applicability ranges and a novel pointing system. 159 oilfields in Türkiye were characterized based on reservoir properties and categorized as heavy, weak and strong aquifer support. The characterization revealed how source rock type and regional paleo-tectonic events dictate primary recovery and need for EOR. The EOR assessment implemented promised 58 applicable cases out of 315. Carbon dioxide (CO2) injection is applicable for many fields, which could stimulate feasibility of carbon capture projects in the country. Immiscible nitrogen injection might be an alternative for many of the medium and light oil reservoirs in the absence of CO2. Polymer flooding is also promising mainly for fields having weak-aquifer support. However, our hands-on experience suggests that conformance control is required to control flow of EOR agent in densely fractured carbonates. Thermal methods do not seem applicable in heavy oil reservoirs due to depth limitations except in-situ combustion, which requires pilot test confirmation. Provided methodology in this study may be used as a guideline for other fields to assess EOR potential.

Degradation and enhanced oil recovery potential of Alcanivorax borkumensis through production of bio-enzyme and bio-surfactant

Microbial enhanced oil recovery (EOR) has become the focus of oilfield research due to its low cost, environmental friendliness and sustainability. The degradation and EOR capacity of A. borkumensis through the production of bio-enzyme and bio-surfactant were first investigated in this study. The total protein concentration, acetylcholinesterase, esterase, lipase, alkane hydroxylase activity, surface tension, and emulsification index (EI) were determined at different culture times. The bio-surfactant was identified as glycolipid compound, and the yield was 2.6 ± 0.2 g/L. The nC12 and nC13 of crude oil were completely degraded, and more than 40.0 % of nC14–nC24 was degraded by by A. borkumensis. The results of the microscopic etching model displacement and core flooding experiments showed that emulsification was the main mechanism of EOR. A. borkumensis enhanced the recovery rate by 20.2 %. This study offers novel insights for the development of environmentally friendly and efficient oil fields.

A Laboratory Experimental Study on Enhancing the Oil Recovery Mechanisms of Polymeric Surfactants.

In order to evaluate the physical and chemical properties of polymer surfactants and analyze their oil displacement mechanisms, three types of poly-surfactant used in the Daqing oil field were chosen to be researched, and the oil displacement effects were studied using poly-surfactants of different viscosity, dehydrating rate, and core permeability. The main purpose is to determine the reasonable range of different characteristic indexes of polymeric surfactant flooding. The oil displacement effect of 15 cores was analyzed, and the effects of viscosity, the dehydrating rate of emulsion, and permeability on EOR (Enhanced Oil Recovery) were analyzed. The oil displacement mechanisms of polymeric surfactants were researched using a photolithographic glass core. This paper explores the mechanism underlying production enhancement as an EOR target, while simultaneously conducting laboratory tests to assess the physical and chemical properties of polymeric surfactants. The poly-surfactant agents exhibit a notable increase in viscosity, with the optimal displacement effect observed at a core effective permeability exceeding 400 mD, resulting in a potential EOR of 15% or higher. Moreover, at a viscosity ranging between 40 and 70 mPa·s, the total EOR can reach 73%, with the peak efficiency occurring at a viscosity of 60 mPa·s. The water loss rate of the emulsion, ranging between 30% and 70%, achieves optimal performance at 50%. The poly-surfactants' higher viscosity extends the oil sweep area, enhancing recovery efficiency, and noticeably reducing residual oil compared to water flooding. During poly-surfactant flooding, a substantial amount of residual oil is extracted and transformed into droplets. The rapid emulsification of the polymeric surfactant solution with crude oil forms a stable emulsion, contributing to its significant oil recovery effect. This research provides valuable technical support for EOR in thin and low-quality reservoirs of onshore multi-layered sandstone reservoirs.

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.

Scope of Implementation of Low Salinity Nanofluid to Improve Oil Recovery in a Part of the Hapjan Oil Field of Upper Assam Basin

The application of nanoparticles in the field of Enhanced Oil Recovery (EOR) has been an emerging technology in recent years. Earlier studies have shown that the nanofluids containing nanoparticles (NPs) of average size (<100 nm) can enhance the oil recovery through wettability alteration of rock, reduction of mobility ratio, reduction of oil-aqueous solution interfacial tension (IFT), reduction of sand production and improvement of sweep efficiency. Low Salinity Waterflooding (LSW) has been utilized as a promising EOR method in the last two decades. Recent studies have found that nanoparticle-assisted LSW embraces both nanoparticles and ions as EOR agents in the injection brine. This study investigates the scope of implementation of the low salinity nanofluid EOR using silica nanoparticles to improve oil recovery in the Tipam Reservoir Sandstone of the Hapjan Oil Field of Upper Assam Basin, India. The analysis of the reservoir brine, reservoir rock and crude oil shows the presence of divalent cations (Ca2+ and Mg2+), clay minerals (Illite and Smectite) and polar compounds (Asphaltene and Resin) respectively. The presence of the divalent cations, clay minerals and polar compounds in the Crude Oil/Brine/Rock system of a sandstone reservoir is the prerequisite for implementing low salinity nanofluid EOR. The study shows that the low salinity nanofluids can shift the wettability of the rock to a more water-wet state. It is also observed that the silica nanoparticles can increase the nanofluid viscosity and reduce the oil-nanofluid IFT, which can improve the recovery of oil. The experimental results show that the study area has great potential for the low salinity silica nanofluid EOR to improve oil recovery.

Anionic-nonionic and nonionic mixed surfactant systems for oil displacement: Impact of ethoxylate chain lengths on the synergistic effect

Compound surfactant system has been extensively studied in enhanced oil recovery (EOR) as the synergistic effect of mixed surfactants can increase the density of surfactants distributed at the oil/water interface, enhancing the interfacial activity and decreasing the interfacial tension. The system can further increase the capillary number and enhance oil recovery for oil-wet reservoirs. Studying the interactions between surfactant molecules is of great significance to the enhancement of practical application performances. In this study, N, N-dihydroxyethyl alkyl amide (CDEA), and Alkylphenol polyoxyethylene carboxylate (APEC) with different EO numbers were mixed to prepare a binary compound oil displacement system. The influence of the EO number on the synergistic effect of the CDEA/APEC system and the EOR potential was measured by interfacial tension, nanomechanical tests and oil-displacement experiments. The results indicate a synergistic effect between CDEA and APEC due to the formation of hydrogen bonds between the hydroxyl groups of CDEA and the EO chains of APEC. An optimal synergistic effect in the system was obtained when the EO number was four. The CDEA/APEC-4 system exhibited an oil/water interfacial tension decrease to 10−2 mN/m at 75 °C and the oil recovery was 57.14 %, which was increased by 19.2 % compared to primary water flooding. However, a longer EO chain length weakened the interaction forces between CDEA and APEC, which diminished the synergistic effect of the system, leading to an increase of the interfacial tension. Due to the flexibility of the EO chain, the increase in the EO number leads to the bending of APEC molecules. The longer EO chain length weakened the interaction forces between CDEA and APEC, which diminished the synergistic effect of the system, leading to an increase of the interfacial tension. The oil-displacement experiment revealed that the EO chains changed the oil recovery and injection pressure by affecting the interfacial tension of the mixed system. This study has significant implications for the formulation design and optimization of agents for oilfield development.

Synthesis of amphiphilic Janus SiO2/styrene butyl acrylate polymer microspheres and their application in oil recovery

We report the design and synthesis of two kinds of amphiphilic Janus SiO2 nanoparticles, including polyacrylic acid/polystyrene (PAA/PS) Janus SiO2 and polyacrylic acid/polymethylmethacrylate (PAA/PMMA) Janus SiO2. The amphiphilic Janus SiO2 nanoparticles can effectively stabilize polystyrene butyl acrylate (P(St-BA)) composite microspheres, forming low-cost oil displacing systems to improve the oil recovery of heterogeneous and low-permeability reservoirs. Among them, the PAA/PS Janus SiO2 stabilized P(St-BA) are demonstrated with good injection, migration, and plugging performance, as well as high temperature and salt resistance. These advantages enable the system an oil recovery increment of 32%. In addition, the microspheres also present good enhanced oil recovery potential in heterogeneous reservoirs, especially for cores with a permeability ratio of 2.0. In principle, the oil displacement of this system is achieved by the synergic effect of amphiphilic Janus SiO2 nanoparticles and composite microspheres. This work thus provides a promising method for high-performance yet low-cost oil recovery improvement.

Evaluation of enhanced oil recovery methods for mature continental heavy oil fields in China based on geology, technology and sustainability criteria

Enhanced oil recovery (EOR) methods in mature oil fields play an irreplaceable role in supporting the long-term and stable production of crude oil. This study establishes a unified and comparable evaluation index system based on geology, technology and sustainability, re-evaluates the existing EOR projects focused on heavy oil extraction by utilizing hybrid AHP-CRITIC-FCE models, and selects the most efficient, economic, and low-carbon footprint EOR technologies to facilitate the development of mature Chinese heavy oil fields. Three main criteria and nineteen subcriteria are considered in the multi-criteria decision-making system. The weights given to criteria are determined by combining the subjective AHP and objective CRITIC methods. The fuzzy comprehensive evaluation method is adopted to prioritize the performance of the EOR process. Empirical analysis is conducted on seven typical heavy oil technologies. The study finds that geological factors account for the largest proportion, and the top five indicators in terms of weight are buried depth, recovery factor, viscosity, operating cost per tonne of oil and reservoir thickness. Three technologies are recommended for potential future green footprint heavy oil EOR methods. This study combines both expert judgment and field data appraisal to help decision makers better plan the future strategic layout of EOR technology.

Geothermal development associated with enhanced hydrocarbon recovery and geological CO2 storage in oil and gas fields in Canada

In this study, reservoir simulations with economic analysis are performed to investigate the potential of utilizing oil and gas fields for geothermal development associated with enhanced hydrocarbon recovery and geological CO2 storage. Results show that the revenue from CO2 enhanced oil recovery, CO2 storage and geothermal development accounts for 54%, 40%, and 6% of the total revenue to repurpose oil fields, respectively. Meanwhile, the revenue from CO2 enhanced gas recovery, CO2 storage and geothermal development accounts for 12%, 82%, and 6% of the total revenue to repurpose gas fields, respectively. Additionally, the revenue is 18% higher from converting wells to enhanced hydrocarbon recovery, CO2 storage and geothermal development in the oil fields than those in the gas fields. We then conduct a first-of-its-kind evaluation of 16,990 oil fields and 71,907 gas fields in Canada for geothermal development with enhanced hydrocarbon recovery and geological CO2 storage. Results show that 213 oil fields and 2,639 gas fields with a reservoir temperature above 100 °C and buried depth of 800 m or deeper are suitable for the CO2 storage and heat mining projects. The 213 oil fields have CO2 enhanced oil recovery potential of 643 million barrels, geothermal resources of 4.5 billion GJ and CO2 storage capacity of 552 Mt. The 2,639 gas fields have CO2 enhanced gas recovery potential of 6.3 Tcf, geothermal resources of 16 billion GJ and CO2 storage capacity of 8 Gt.

Synthesis and Enhanced Oil Recovery Potential of the Bio-Nano-Oil Displacement System.

Nanoparticles (NPs) have attracted great attention in the tertiary oil recovery process due to their unique properties. As an economical and efficient green synthesis method, biosynthesized nanoparticles have the advantages of low toxicity, fast preparation, and high yield. In this study, with the theme of biotechnology, for the first time, the bio-nanoparticles reduced by iron-reducing bacteria were compounded with the biosurfactant produced by Bacillus to form a stable bio-nano flooding system, revealing the oil flooding mechanism and enhanced oil recovery (EOR) potential of the bio-nano flooding system. The interfacial properties of the bio-nano-oil displacement system were studied by interfacial tension and wettability change experiments. The enhanced oil recovery potential of the bio-nano-oil displacement agent was measured by microscopic oil displacement experiments and core flooding experiments. The bio-nano-oil displacement system with different nanoparticle concentrations can form a stable dispersion system. The oil-water interfacial tension and contact angle decreased with the increase in concentration of the bio-nano flooding system, which also has a high salt tolerance. Microscopic oil displacement experiments proved the efficient oil displacement of the bio-nano-oil displacement system and revealed its main oil displacement mechanism. The effects of concentration and temperature on the recovery of the nano-biological flooding system were investigated by core displacement experiments. The results showed that the recovery rate increased from 4.53 to 15.26% with the increase of the concentration of the system. The optimum experimental temperature was 60 °C, and the maximum recovery rate was 15.63%.

Further discussion of CO2 huff-n-puff mechanisms in tight oil reservoirs based on NMR monitored fluids spatial distributions

Due to the poor physical properties of tight reservoirs, CO2 huff-n-puff (HNP) is considered a potential enhanced oil recovery (EOR) method after primary depletion. Optimization plays a critical role in the effective implementation of CO2 huff-n-puff. But the optimization requires a good understanding of the EOR mechanisms. In this work, the spatial distribution of oil saturation under different experimental conditions was analyzed by the NMR method to further discuss the HNP mechanisms. According to the variation of 1D frequency signal amplitude, we divided the core into the hardly movable area and movable area, the region with the obvious signal decline was defined as the movable area, and the hardly movable area was the region with limited signal decline. Based on that the recovery characteristics of different scenarios were evaluated. Firstly, the necessity of the soaking stage was studied, where three scenarios with different soaking times were carried out. Secondly, the injection pressure was adjusted to investigate the effect of the pressure gradient. The T2 spectra show that soaking has significantly improved the production of crude oil in small pores, and higher oil recovery in a single cycle is observed, but it is lower when the elapsed time (total operation time) is the same. 31.03% of oil can be recovered after 3 cycles HNP, which increases to 33.8% and 37.06% for the 4 cycles and 6 cycles cases. As the pressure gradient increases, more oil is removed out of the matrix, and the oil in the deep part of the reservoir can be effectively recovered. During the CO2 huff-n-puff process, the oil distributions are similar to the solution gas drive, the residual oil is distributed at the close end of the core and the range that the oil can be efficiently recovered is limited.

Controlled salinity water flooding and zeta potential: Insight into a novel enhanced oil recovery mechanism

Controlled salinity water flooding also known as engineered water flood has been tested as a potential enhanced oil recovery (EOR) method in laboratory as well as at pilot/field scale. However, there are cases seen where the method has failed to show its potential for EOR. Scientists believe that the lack of understanding of case specific underlying mechanism is the primary reason. Many of the literatures claims reduction of interfacial tension as the primary oil recovery mechanism; but recent findings highlighted that modification of electrical charges on rock surface with response to injection brine salinity has greater effect. In order to investigate the same and in search of more insightful mechanism, in this study we have designed and performed experiments with selected chemicals which can modify surface properties of sandstone and also the oil water interfacial tension. The electrical charge of the rock surface and oil–brine​ interfacial tension were modified by tuning salinity of injection water and adding surfactants (sodium dodecyl benzene sulfonate, SDBS and cetyltrimethylammonium bromide, CTAB). The electrical charge of the sandstone surfaces was quantified with zeta potential measurement. The oil recovery potential of the injection fluids was tested through laboratory core flooding experiments at controlled near reservoir conditions. Superposition of all the obtained results revealed that low salinity injection brine modifies the sandstone surface to higher negatively charged state than high salinity water. Therefore, with a negatively charged oil–brine interface it causes strong repulsive forces promoting detachment of residual oil and subsequent mobilization. The hypothesis is also proved by the fact that SDBS in spite of resulting in a lower interfacial tension reduction than CTAB yielded higher oil recovery. This is because of the negative zeta potential caused by SDBS to sandstone surface in comparison to the positive zeta potential observed in the case of CTAB.

Effect of nanoparticles and nanosheets on improving the oil/water interface performance of surfactants in enhancing oil recovery: A comparative study by molecular simulation

In recent years, nanoparticles have become the most potential enhanced oil recovery technology because of their unique small size effect and specific surface area effect. With the research and application of graphene and its derivative materials, nanosheets are one of the research hotspots of nanomaterials for enhanced surfactant flooding. However, as far as we know, the molecular simulation comparison of nanoparticles and nanosheets to enhance the performance of surfactants has not been reported so far. Therefore, in this paper, we constructed nano-SiO2 particles grafted with hydroxyl and pentyl alkane activator, graphene nanosheets grafted with carboxylic acid chain and pentyl alkane activator for the first time. On this basis, the interfacial tension, interfacial density, interfacial generation energy and radial distribution function were analyzed by molecular dynamics simulation. The results show that nanoparticles and nanosheets have synergistic effect with amphoteric surfactant dodecyl dimethyl aminoethyl lactone (BS-12). The synergistic effect of nanosheets and BS-12 was stronger after carboxylic acid chain and pentyl alkane activator are grafted on the surface of nanosheets. The interfacial tension of n-dodecane/water could be reduced to 13.58 mN/m after the modified nanosheets are compounded with BS-12. The interfacial tension of n-dodecane/water could be reduced to 4.15 mN/m by the modified nanosheets are compounded with BS-12, and the ability of reducing the interfacial tension between oil and water is significantly improved. The calculation of n-dodecane/water interface thickness and interface formation energy showed that compared with the modified nanoparticles and BS-12 compound system, the interface thickness of the modified nanosheets and BS-12 compound system increased by 9.24%, and the interface formation energy increased by 17.85%. In addition, the results of radial distribution function analysis also demonstrated that the modified nanosheets had strong hydration with water molecules after being compounded with BS-12. The results of this work can provide new ideas for further research on the synergistic effect of surfactants and nanomaterials, as well as the development of oil displacement technology based on surfactants/nanomaterials.

A novel CO2-resistant dispersed particle gel for gas channeling control in low-permeability reservoirs

A novel CO2-resistant dispersed particle gel (CR-DPG) for gas channeling control was successfully prepared by shearing an organic–inorganic composite bulk gel. The basic properties, CO2-resistance characteristics, gas channeling control capacity and enhanced oil recovery potential were systemically investigated. The prepared CR-DPG particles were regular spheres, which could maintain a uniform dispersion during the injection process. The CO2 resistance test was carried out at 90 ℃ and CO2 pressure of 20 MPa. After the CO2 resistance test, the dispersion stability of CR-DPG decreased, and the particles coalesced to form large aggregates instead of degrading, exhibiting excellent CO2 resistance. Furthermore, the mechanical strength of the CR-DPG particles aged for different time was measured using atomic force microscope (AFM). Due to the silica gel particles, the CR-DPG particles retained high mechanical strength in the long-term experiment, which could maintain a high plugging effect for a long time during CO2 flooding. A fractured core flowing model was employed to investigate gas channeling control capacity and EOR potential of CR-DPG. The CR-DPG particles could migrate to fractures in-depth, in which particles coalesced to form large aggregates and adsorbed to mitigate gas channeling. In addition, CR-DPG had great potential for enhanced oil recovery by 10.4 %. This work provides an alternative material with a simple preparation process and low cost for gas channeling control in oilfields with CO2 flooding.

Rapid evaluation model for EOR techniques applicability of gas flooding, foam flooding and surfactant flooding based on modified fractional flow theory

Before a wide range of enhanced oil recovery (EOR) techniques were implemented for an oilfield, the EOR potential and economic evaluation of the techniques should be evaluated in advance for each reservoir to determine which EOR technique was proper. In an oilfield developed with fluvial delta reservoirs, the complicated distribution of scattered small reservoirs in vertical and horizontal directions brought trouble for evaluation work. A rapid and reliable evaluation model for EOR techniques applicability was necessary to deal with the evaluation simulation for many small reservoirs of an oilfield. Combining fraction theory model with auxiliary equations, which describe the effect of formation heterogeneity and mechanism of different EOR technique on fractional flow rate, an evaluation analysis method for EOR techniques applicability of gas flooding, foam flooding and surfactant flooding was proposed. In the gas flooding model, the minimum miscible pressure of impure gas was introduced, and the relative permeability was modified by the minimum miscible factor. In the foam flooding model, changes in the mobility ratio and chemical adsorption were considered and a reduction factor of mobility ratio was introduced. In the surfactant flooding model, calculation formulas of viscosity and interfacial tension as well as the relative permeability were introduced. Finally, the model was simulated for a low permeability reservoir, and the simulation results were compared with that from Eclipse software. The similar results, little calculation time and feasibility of predicting optimal injection parameter had shown the reliability of the rapid evaluation model.

Polysulphate: A New Enhanced Oil Recovery Additive to Maximize the Oil Recovery From Carbonate Reservoirs at High Temperature

Summary Seawater (SW) injection is an enhanced oil recovery (EOR) success in the North Sea carbonate reservoirs due to wettability alteration toward a more water-wet state. This process is triggered by the difference in composition between injection and formation water (FW). “Smartwater” with optimized ionic composition can easily be made under laboratory conditions to improve oil recovery beyond that of SW. However, in the field, its preparation may require specific water treatment processes, e.g., desalination, nanofiltration, or addition of specific salts. In this work, a naturally occurring salt called Polysulphate (PS) is investigated as an additive to produce smartwater. Outcrop chalk from Stevns Klint (SK), consisting of 98% biogenic CaCO3, was used to investigate the potential and efficiency of the PS brines to alter wettability in chalk. The solubility of PS in SW and deionized water, and brine stability at high temperatures were measured. Energy dispersive X-ray and ion chromatography were used to determine the composition of the PS salt and EOR solutions, and to evaluate the sulphate adsorption on the chalk surface, a catalyst for the wettability alteration process. Spontaneous imbibition (SI), for evaluating wettability alteration of PS brines into mixed-wet chalk was performed at 90 and 110°C and compared against the recovery performance of FW and SW. The solubility tests showed that the salt was easily soluble in both deionized water and SW with less than 5% solid residue. The deionized PS brine contained sulphate and calcium ion concentrations of 31.5 and 15.2 mM, respectively, and total salinity was 4.9 g/L. This brine composition is very promising for triggering wettability alteration in chalk. The SW PS brine contained 29.6 mM calcium ions and 55.9 mM sulphate ions, and a total salinity of 38.1 g/L. Compared with ordinary SW, this brine has the potential for improved wettability alteration in chalk due to increased sulphate content. Ion chromatography revealed that the sulphate adsorbed when PS brines were flooded through the core, which is an indication that wettability alteration can take place during brine injection. The reactivity was also enhanced by increasing the temperature from 25 to 90°C. Finally, the oil recovery tests by SI showed that PS brines were capable of inducing wettability alteration, improving oil recovery beyond that obtained by FW imbibition. The difference in oil recovery between ordinary SW and SW PS imbibition was smaller due to the already favorable composition of SW. PS brines showed a significant potential for wettability alteration in carbonates and are validated as a potential EOR additive for easy and on-site preparation of smartwater brines for carbonate oil reservoirs. PS salt, added to the EOR solution, provides the essential ions for the wettability alteration process, but further optimization is needed to characterize the optimal mixing ratios, ion compositions, and temperature ranges at which EOR effects can be achieved.

Utilization mechanism of foam flooding and distribution situation of residual oil in fractured-vuggy carbonate reservoirs

The development of fractured-vuggy carbonate reservoirs is extremely difficult because of the complex fractured-vuggy structure and strong heterogeneity. Foam flooding is a potential enhanced oil recovery (EOR) technology in fractured-vuggy carbonate reservoirs. Based on the similarity criterion, three types of 2D visual physical models of the fractured-vuggy structure were made by laser ablation technique, and a 3D visual physical model of the fractured-vuggy reservoir was made by 3D printing technology. Then the physical analog experiments of foam flooding were carried out in these models. The experimental results show that foam can effectively improve the mobility ratio, control the flow velocity of the fluid in different directions, and sweep complex fracture networks. The effect of foam flooding in fractures can be improved by increasing foam strength and enhancing foam stability. The effect of foam flooding in vugs can be improved by reducing the density of the foam and the interfacial tension between foam and oil. Three types of microscopic residual oil and three types of macroscopic residual oil can be displaced by foam flooding. This study verifies the EOR of foam flooding in the fractured-vuggy reservoir and provides theoretical support for the application of foam flooding in fractured-vuggy reservoirs.

Pore scale performance evaluation and impact factors in nitrogen huff-n-puff EOR for tight oil

Nitrogen huff-n-puff (N2 HnP) appears to be an economical and high-efficiency enhanced oil recovery (EOR) technique for tight oil reservoirs. There is however a lack of understanding of the pore-level EOR performance of N2 HnP under tight reservoir conditions. In this work, a non-magnetic reactor was created and combined with a nuclear magnetic resonance (NMR) device for real-time monitoring of oil distribution in the HnP experiment. N2 HnP experiments were then performed in a tight sandstone core sample at a temperature of 353 K and an injection pressure ≥ 24 MPa. The pore-level oil distribution under reservoir conditions was monitored and the EOR performance of N2 HnP in specific pores was analyzed. The pore throat structures of the core sample and the phase behavior of the N2-oil system were analyzed to elucidate the EOR mechanism of N2 HnP. An oil recovery factor of 37.52% can be achieved after four cycles, which proves the EOR potential of N2 HnP for tight reservoirs. The highest recoveries after N2 HnP are obtained in the large pores, followed by the medium pores, the small pores, and finally the micro pores. Increases in soaking time and injection pressure resulted in slight and pronounced increases in oil recovery, respectively, both of which are mainly reflected in the first cycle. Specifically, increasing the soaking time only slightly improves the cumulative oil recovery in the small pores while increasing the injection pressure significantly improves the cumulative oil recovery in the small, medium, and large pores simultaneously. However, variations in both injection pressure and soaking time have a negligible effect on the cumulative oil recovery of the micro pores.

Technical Evaluation of a Surfactant Injection Process for Heavy Oil Recovery by Laboratory-Scale Numerical Simulation

Abstract Surfactant flooding comes up as a potential enhanced oil recovery method for heavy oil exploitation as a solution to energy losses in thermal processes. This research aims to use an inverse problem to determine the most suitable application scenario of this process at the laboratory scale by the use of reservoir simulation. First of all, a numerical laboratory model was built, representing an alkali-surfactant flooding test of crude oil with a viscosity of 1800 MPa*s; second, an optimization process was carried out, where operational parameters, such as alkali and surfactant concentration, size of the main chemical slug and injection rate, were evaluated. Results showed that the most suitable scenario consisted of the injection of 0.5 PV from the combined mixture 0.2% Na2CO3 + 0.2% NaOH + 100 ppm Surfactant at an injection rate of 0.1 cm3/min, getting a final chemical-oil relation of about 0.0010 cm3 of chemical per cm3 of oil.

Stability mechanisms of viscoelastic zwitterionic-anionic surfactants enhanced foam system for low-permeability reservoirs

Polymers are generally applied to enhance foam stability and boost the efficiency of foam flooding for enhanced oil recovery (EOR). In low-permeability reservoirs, the polymers can unavoidably damage the formation. In this study, a novel viscoelastic surfactant system was developed by combining zwitterionic surfactant erucic acid amide propyl hydroxysulfonyl betaine (EHSB) and anionic surfactant sodium dodecyl sulfate (SDS) to enhance air foam stability without damaging the formation in low-permeability reservoirs. The Waring Blender method was used to comprehensively investigate the foam parameters, including foaming volume, drainage half-life, and foam half-life under practical formation conditions. After that, an optical microscope and Turbiscan stability analyzer were used to study the stability of the foam. The interfacial viscoelasticity, electric double layer, and continuous phase viscoelasticity were investigated to clarify the stability mechanisms. The results indicate that the foam composite index of the optimum formulation 0.3 % EHSB-SDS (mass ratio = 1.1:1) system was 175500 min·mL, which is 6 times higher than that of EAB-SDS system with a same viscosity. The EHSB-SDS system also provides a certain degree of strong resistances on temperature and crude oil, which has fair stability below 55 °C and 10 % oil content. EHSB-SDS has stronger interfacial strength and foam stability than EAB-SDS system due to its higher interfacial elastic modulus and surface activity. Meanwhile, the EHSB-SDS has a higher absolute value of Zeta potential (34.91 mV) than EAB-SDS (20.66 mV), indicating a stronger electrostatic repulsion. Hence, the newly viscoelastic surfactant-enhanced foam possesses sufficient stability and exhibits great EOR potential in low-permeability reservoirs.