Oil Recovery Performance Research Articles

Effects of viscosification, ultra-low interfacial tension, and emulsification on heavy oil recovery by combination flooding

Heavy oil recovery mechanisms by combination flooding have well recognized as viscosification, ultra-low interface tension (IFT) and emulsification, however, the role or relative contribution of each mechanism to oil recovery is still not clear (especially under different water-oil viscosity ratios). To address this, two emulsified and one ultra-low IFT mixtures were collected and systematically compared in their IFT, emulsion stability and oil recovery performances. The results show that, as excepted, the used formulas have different IFT and emulsion stability properties: for the ultra-low IFT one, IFT indeed reaches an ultra-low level, but the stability of its emulsion is very poor. The emulsified formulas (with non-ultra-low, ultra-low IFT) are more powerful in stabilizing heavy oil emulsion than the former. Significant discrepancy in combination flooding under different viscosity ratios in homogeneous and heterogeneous models reveals that: when the viscosity ratio is lower than 0.2, the mobility control by the combination mixture is insufficient, and the contribution of emulsification is relatively high (6.4–24.0 %), the dominant oil recovery mechanism is the synergy of those three mechanisms. As the viscosity ratio gets higher than 0.2, the mobility control is strong, resultingly, the contribution of emulsification is reduced, making it less important. In addition, although the presence of heterogeneity does not change the critical value of viscosity ratio, it has a significant impact on the detailed contribution of the dominant mechanisms.

Wettability Alteration with Weak Acid-Assisted Surfactant Flood

Summary Oil-wetness and heterogeneity are two key reasons for low oil recovery by waterflooding in carbonate reservoirs. Surfactants have been effective in altering the oil-wet matrix to a more water-wet condition and initiating spontaneous imbibition. Because it takes time for the surfactant to alter wettability, oil recovery from the tight matrix is slow and sometimes not economically feasible. Acids have the potential of dissolving minerals, which may alter wettability. In this study, the enhanced oil recovery (EOR) performance of an acid-assisted surfactant solution, a novel technique, was evaluated for low-temperature applications. A set of acids and their acetates were tested. Bulk rock-acid reaction, wettability alteration (WA) tests, and spontaneous imbibition measurements were conducted at reservoir temperature (35°C) to identify effective candidates. Coreflood tests were then performed to evaluate the selected acid-surfactant formulations. Before and after a coreflood test, the core was scanned using micro-computed tomography (CT) to investigate pore structure alteration. Bulk reaction measurements showed that weak acids, especially acetic acid (AA), have the desired low reaction rates at 35°C. WA tests showed that AA can remove the crude oil off the rock surface and alter wettability through mineral dissolution. The surfactant can reduce contact angles from 160° to 58°; adding acid into the surfactant can further reduce it to 52°. Spontaneous imbibition experiments showed the synergy between the acid and the surfactant; the AA-surfactant solution had the highest oil recovery (62.6%) among acid-surfactant formulations. The acid improves the WA efficiency by the surfactant through surface mineral dissolution and lower ζ-potential. The imbibition transports the acid-surfactant solutions into the matrix, which minimizes face dissolution. Coreflood tests show that the AA-surfactant flood can increase the oil recovery rate and recover about 8% more oil compared to the surfactant flood. Micro-CT showed that a few mineral particles were transported along the core and partially plugged pore throats, which reduced permeability and diverted flow leading to improved oil recovery. The transport of the acid in reservoirs and the potential plugging issues have to be carefully evaluated in future studies.

Experimental investigation of hydrophobic and hydrophilic silica nanoparticles on extended surfactant properties: Micro-emulsion, viscosity, and adsorption behaviors

The novel applications of nanoparticles and surfactants are of interest for improving chemical oil recovery performance. In this study, two types of hydrophobic and hydrophilic SiO2 nanoparticles (NPs) were used in conjunction with a binary surfactant system (extended Carboxylate and Dioctyl sulfosuccinate (AOT) surfactants at the ratio of 0.6:0.4 by volume). An extensive series of experiments were performed in the presence of API brine containing NaCl: CaCl2 at the 8:2 wt ratio to study microemulsion phase behavior, interfacial tension (IFT), surfactant adsorption onto NP surfaces, solution and microemulsion viscosity, and oil recovery. The results indicate that the microemulsion phase behavior, optimum salinity (S*), and IFT were influenced by the concentrations and surface characteristics of the NPs. Hydrophobic or hydrophilic NPs at 500 ppm in the binary surfactant system could form Type III microemulsion and decrease the S* from 2 to 1.75 wt%. When the NP concentration reached 1000 ppm, the S* reduced to 1.5 wt%. The IFT value of the neat binary surfactant system at the S* was obtained in an ultralow range (0.0013 mN/m), and the IFT value of the hydrophobic NPs exhibited a more significant reduction than the hydrophilic NP systems. The adsorption result demonstrates that Carboxylate surfactant had lower adsorption onto hydrophilic NP than AOT. COSMO σ-profile and screened charge density illustrated that the low coverage of Carboxylate surfactant was from hydrogen bonding interaction, making the surfactant lie flat on the surface. The viscosity of the NP-surfactant solution was affected by the capacity of the surfactant adsorption onto the NP surface. In this regard, adding the hydrophobic NPs at 1000 ppm provided the highest solution viscosity over the entire shear rate and temperature range. The viscosity of the microemulsion formulated by hydrophobic NPs was higher than that of the microemulsion formulated by the hydrophilic NPs. The system with the lower NP concentration had higher microemulsion viscosity than the system with the higher NP concentration. The oil recovery results indicate that the appropriate NP type and concentration in the surfactant system could increase the displacing viscosity and decrease the microemulsion viscosity compared with the neat surfactant flooding system. The success in improving oil recovery was achieved with recovery efficiency of 88% original oil in place (OOIP).

Citric acid-based N-alkyl amides for enhanced oil recovery application in the carbonate reservoir: Sustainable laboratory-scale synthesis and recovery performance

Various chemical compounds and nanoparticles have been developed and utilized for upstream oilfield applications, regardless of their environmental impact. The majority of these oilfield chemicals were designed from oil-based starting materials and synthesized in multi-steps using hazardous solvents. However, there is an urge to improve sustainability in developing oilfield chemicals to reduce CO2 emissions and utilize eco-friendly materials. Herein, we propose a sustainable synthesis of citric acid-based N-alkyl amides using solvent-free reaction and green starting material. The N-alkyl amide compounds were prepared by condensation reaction between citric acid and N,N-dimethyl-1,3-propanediamine (DMPA) or N,N-diethylethylenediamine (DEEA). The resulting compounds demonstrated good stability in reservoir conditions and were used for enhanced oil recovery. The structure/property relationships between the N-alkyl amides and their oil recovery performance were investigated systemically. The CA-based N-alkyl amides resulted in cumulative oil recovery of 44.7%–48.3%, which is 90% higher than the commonly used surfactants such as α-Olefin Sulfonate (AOS) and Cetrimonium bromide (CTAB). This study paves the way to develop green-based materials for upstream applications to move toward efficient and cleaner production.

A COMPARATIVE STUDY ON THE OIL RECOVERY PERFORMANCE OF THE CO2 AND N2 HUFF-N-PUFF PROCESSES IN LOW PERMEABILITY CORES

The gas huff-n-puff process has been widely employed in low permeability reservoir development practices. At present, the understanding of synergistic effects of different injection fluids and rock permeability is still limited and is worthy of in-depth investigation. Therefore, laboratory studies on oil recovery performance of supercritical CO<sub>2</sub> (scCO<sub>2</sub>) and N<sub>2</sub> huff-n-puff processes in ultra-low (< 0.5 mD), extra-low (0.5-1 mD), and average-low permeability (1-10 mD) core samples were systematically investigated. More effective cycles could be achieved in the CO<sub>2</sub> huff-n-puff process than in the N<sub>2</sub> process. The CO<sub>2</sub> huff-n-puff operation could produce 29.9% oil in the ultralow permeability core, which is obviously higher than 20.2% for N<sub>2</sub>. With increasing core permeability, the oil recovery ratio for both the scCO<sub>2</sub> and N<sub>2</sub> huff-n-puff processes increases as well. Laboratory results show oil recovery ratios of 33.1% and 47.3% for the scCO<sub>2</sub> process in 0.5 mD and 10 mD cores and 36.3% and 49.1% for the N<sub>2</sub> process in 0.5 mD and 9.5 mD cores, respectively. Although the oil recovery rates for the N<sub>2</sub> and CO<sub>2</sub> huff-n-puff processes are close in the 0.5 mD and 10 mD cores, the effective oil extraction pressure for the scCO<sub>2</sub> puff process is found to be 5~10 MPa, which is much higher than 0~2 MPa for the N<sub>2</sub> puff process. The study's findings can help provide a better understanding of the oil extraction behaviors in the huff-n-puff process with different injection fluids as well as in different low permeability cores.

Simultaneous solar-driven seawater desalination and continuous oil recovery

Oil spills and freshwater scarcity remain two worldwide challenging issues. Emerging efforts have been made either to recover oil from oil/water mixture or to extract freshwater from abundant seawater. However, almost all current devices focus on oil recovery or seawater desalination separately, which is lack of energy efficiency. Herein, we propose a design of mechanically robust, bi-functional graphene devices (BGDs), containing vertical graphene sheets decorated on inverted U-shaped graphene monoliths, to achieve simultaneous solar-driven vapor generation and continuous oil recovery from oil-contaminated seawater. Benefiting from the unique wettability design of the BGDs, water evaporates on the hydrophilic surfaces, and meanwhile oil can be spontaneously recovered through the hydrophobic/oleophilic interior channels due to siphon action. Moreover, the strong photothermal effect of vertical graphene can boost both the seawater desalination and oil recovery performance. As a result, a vapor generation rate of 2.04 kg m−2 h−1 and an oil recovery rate of 105.8 L m−2 h−1 are concurrently achieved under 1-sun irradiation. The design of bi-functional devices provides a new means to maximize the utilization of solar power and reduce the costs for multi-functional practical environmental engineering applications.

Uncertainty quantification for CO2 storage during intermittent CO2-EOR in oil reservoirs

CO2 enhanced oil recovery (CO2-EOR) process is considered the most feasible option for a secure storage of CO2 in underground formations. However, predicting amounts of CO2 stored and the oil recovered is associated with high risks due to data uncertainty. Sources of uncertainty lie in the challenges of accurately characterizing reservoir properties. Hence, the main objective of this study is to quantify the uncertainty of CO2 storage and oil recovery during intermittent CO2-assisted gravity drainage (CO2-GAGD) EOR process with a focus on key uncertain parameters including reservoir properties (permeability heterogeneity, porosity, and compressibility); fluid properties (CO2 diffusion coefficient and Henry's constant); and rock-fluid properties (gas-oil relative permeability data). Additionally, we aim to generate a rapid tool that reduces the computational expenses of the compositional reservoir simulation process by employing artificial neural network (ANN) as a machine learning (ML) tool. ANN was applied to generate predictive models that accurately predicted oil recovery and gas storage during the intermittent CO2-GAGD process. A total of 173 numerical samples were simulated and the objective functions were obtained. From the defined ranges of input variables and simulation results, cumulative distribution functions (CDFs) were obtained and uncertainty bounds, i.e., P10, P50, and P90, were estimated. Additionally, the generated ANN model showed excellent predictions of the objective functions with high correlation coefficients, higher than 0.98 in most of the cases, and with an absolute average percentage error (AAPE) range from 2.6 to 9%. Finally, the results of sensitivity analysis, conducted using the developed ML models with generating 10,000 realizations from the input and output parameters, showed the most influential input parameters on the performance of the CO2 storage and oil recovery factor. Reservoir porosity was found to have a significant impact on oil recovery and CO2 storage. A response surface analysis showed that the main independent input parameters contributing to the total uncertainty of oil recovery were horizontal permeability, oil relative permeability, and formation porosity. This study highlights the significant impact of uncertainties of input parameters on simulating the performance of CO2 storage and oil recovery in underground reservoirs.

Remaining oil distribution and recovery performances with waterflooding and surfactant-polymer flooding: An experimental investigation

An oilfield has been developed with waterflooding for a long time, and the water cut has reached a high level. Surfactant-polymer (SP) flooding is considered as the following enhanced oil recovery (EOR) technique. To determine the feasibility of SP flooding in this oilfield, the microscopic oil displacement experiments are performed, and the distribution of remaining oil after waterflooding and SP flooding is observed. The recovery rates are measured by the producing liquid amount and nuclear magnetic resonance (NMR) technique. The two methods show similar measurement results, with deviations of about 10%. The contributions of different pore and throat diameters are analyzed with the NMR technique. The results show that SP flooding has a much lower contribution limit of pore and throat diameter than waterflooding, indicating that SP flooding can effectively improve sweep efficiency. The SP flooding can improve by about 30% EOR rate. The frozen slicing technique and ultraviolet fluorescence excitation are applied to observe the status and distribution of remaining oil. The results show that both waterflooding and SP flooding can effectively reduce all types of remaining oil. Comparing the remaining oil proportions in the high and low permeability cores, we can conclude that the high permeability contributes to the performance of waterflooding and SP flooding. This work proves the efficiency of SP flooding in this oilfield development and provides a microscopic explanation of remaining oil distribution after waterflooding and SP flooding.

Pore-scale study on flow characteristics and enhanced oil recovery mechanisms of polymer microspheres in microchannels

Polymer microsphere flooding is a promising technology for enhancing oil recovery in high water cut reservoirs. Nevertheless, the microscopic flow characteristics and oil recovery mechanisms remain unclear. In this paper, the retention and flow diversion characteristics were investigated by single-microchannel and dual-microchannel chips, respectively. On this basis, the microscopic conformance control and oil recovery performance were studied by pore network model experiments. The influence of concentration and injection rate was discussed. The findings indicate that the polymer microspheres present the discontinuous phase flow characteristics of “temporary plugging-pressurizing-deformation-remigration” in microchannels. They realize flow diversion by alternately plugging wide and narrow microchannels. In porous media, they can inhibit fluid fingering and improve sweep efficiency. As the concentration increases, the sweep efficiency and the oil recovery improve, while the increase in injection rate leads to the opposite result. This work provides microscopic insights into the flow and oil recovery mechanisms of polymer microspheres.

Enhanced oil recovery performance of surfactant-enhanced Janus SiO2 nanofluid for high temperature and salinity reservoir

To improve the dispersion stability of the nanofluid, SDS/Tween 60 surfactant solution was employed as the dispersant for the Janus SiO2 nanofluid. The compounded system showed good dispersion stability and oil displacement effect at high temperature (90 ℃) and high salinity (35000 ppm). The amphiphilic Janus SiO2 nanoparticle was synthesized by Pickering emulsion method. Next, by introducing SDS/Tween60 surfactant system as a dispersant agent, the Janus SiO2 nanofluid could disperse well for more than 12 h at 90 ℃ with a salinity of 35000 ppm. The surfactant-enhanced Janus SiO2 nanofluids showed good dispersion stability in different characterization methods, including visual observation, Turbiscan stability index (TSI) and particle size. Based on the adsorption experiments, the optimal mass concentration ratio between surfactant and Janus nanoparticles was fixed at 2:1. The possible dispersion and stability mechanism of Janus SiO2 nanoparticles was explained from the perspective of the synergistic effect, between surfactants and nanoparticles and between surfactants and surfactants. Then, interfacial tension reduction ability, emulsion stability and wettability alternation capability of surfactant-enhanced Janus SiO2 nanofluid with various concentrations, were studied at 90 ℃ with a salinity of 35000 ppm. The surfactant-enhanced Janus SiO2 nanofluid, with a nanoparticle concentration of 0.01 wt%, showed the best EOR performance. The current study provides a new prospective in preparing Janus SiO2 nanofluids applied for enhanced oil recovery in high temperature and high salinity reservoirs.

Performance Evaluation of CO2 Soaking and Flooding Processes in Tight Oil Reservoirs

CO2 injection has been proven to be an effective method to improve oil recovery of tight oil reservoirs. CO2 soaking and flooding are common processes used to constitute some CO2 injection patterns. To investigate the difference of oil recovery performance and asphaltene precipitation distribution between CO2 soaking and CO2 flooding processes, CO2 soaking and flooding tests under immiscible and miscible conditions were carried out with tight core samples. Then the NMR technique was utilized to analyze the microscopic remaining oil distribution and the asphaltene precipitation distribution after each test. The results indicated that the oil recovery in the small pores less than 0.6 μm was more influenced by the injection pressure, while the oil recovery in the large pores larger than 0.6 μm was more influenced by injection patterns. On the other hand, the asphaltene precipitation degree in different pores is usually relevant to oil recovery. In the large pores, the asphaltene precipitation degree of the soaking process was much lower than that of CO2 flooding by 8.02 and 19.76% under immiscible and miscible conditions, respectively. In the small pores, the asphaltene precipitation degree of the soaking process was higher than that of CO2 flooding by about 4%. Moreover, as injection pressure increased, the asphaltene precipitation caused by the soaking process was much less than that caused by CO2 flooding. The results of the study can provide some theoretical support to determine a better CO2 injection strategy for tight oil reservoirs with different characteristics.

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.

Construction and evaluation of a graphite oxide Nanoparticle-Reinforced polymer flooding system for enhanced oil recovery

Insufficient mobility control capability and limited swept volume are the primary challenges faced by polymer flooding technology. In this work, a graphite oxide nanoparticle-reinforced polymer (GORP) flooding system was constructed. Compared with the conventional polymer (CP) flooding system, the GORP flooding system with 0.15% graphite oxide nanoparticles has a better viscosity increasing effect, shearing resistance and aging stability. In terms of mobility control capability, due to the reinforcing effect of graphite oxide nanoparticles on the three-dimensional polymer network structure, the GORP flooding system has a higher resistance factor and residual resistance factor than the CP flooding system in different permeability cores. In addition, the NMR online displacement experiment results further prove that the enhanced oil recovery performance of the GORP flooding system is more prominent, with a total recovery of 72.87%, which is 5.04% higher than that of the CP flooding system. The GORP flooding system may have the potential to become a long-term effective technology to control the water cut of oil wells.

Wormholes effect in carbonate acid enhanced oil recovery methods

Acid enhanced oil recovery has been a focus of interest in the oil industry due to its significant results on improved recovery, especially in carbonate reservoirs. However, in carbonate reservoirs, highly conductive pathways called “wormholes” are created when acidic fluids are injected into carbonate rocks. Wormholes could jeopardize the enhanced oil recovery outcome and sweep efficiency leaving a substantial volume of oil in the reservoir unswept. This phenomenon has not been investigated yet. The main objective of this study is to identify the impact of these wormholes on the overall oil recovery during enhanced oil recovery practices. This was achieved by injecting acidic fluid into Indiana limestone at various injection rates to control the creation of wormholes. The injection rates were selected based on a proposed dimensionless phase space that predicts the wormholes development and dissolution phase. Our results show that wormholes have a significant impact on the enhanced oil recovery performance resulting in a decrease in the overall oil recovery by 9.6% for portions of the reservoir that experience wormholing. In real field applications, it is recommended to avoid creating wormholes over large portions of the reservoir affected by acid injection as it may jeopardize the field development outcome leaving an unspecified amount of oil in virgin regions in the reservoir which results in additional operational complications. Wormholes are only beneficial near the wellbore for wellbore cleanup and matrix treatment purposes thus providing easier access to the reservoir. However, care needs to be taken to constrain wormhole formation to skin factor reduction and avoid far-reaching wormholes in the reservoir. Cited as: Alarji, H., Clark, S., Regenauer-Lieb, K. Wormholes effect in carbonate acid enhanced oil recovery methods. Advances in Geo-Energy Research, 2022, 6(6): 492-501. https://doi.org/10.46690/ager.2022.06.06

Performance evaluation of produced biopolymers by native strains on enhanced oil recovery

AbstractBio(polymer) flooding is one of the most promising strategy used to recover additional oil from mature reservoirs. Bio(polymers) decrease the mobility ratio, improving the sweep efficiency of injected fluid and consequently, increasing oil recovery. Therefore, in this research seven unknown strains were isolated from the soil of the Masjed‐Soleiman oil field, and then studied for biopolymer production. After biopolymer production and viscosity tests, two of the best strains were selected. Their performances were evaluated in the enhanced oil recovery in micromodel media. The main purpose of this research is to identify the biopolymer‐producing species, but the effective parameters in the production of more biopolymers and enhanced oil recovery are also evaluated and optimized. The experiments optimized by the Design Expert software by the general factorial method. The parameters evaluated include different types of strains, biopolymer concentration (three levels of 500, 5500, and 10,500 ppm) and the salinity of the injected fluid (three levels of 0%, 0.5%, and 10%). The best performance in oil recovery for both strains of TMU57 and TMU59 are considered in the biopolymer concentration of 10,500 ppm and the concentration of NaCl equal to 10 wt%. The values of the ultimate oil recovery in these conditions with the strains of TMU57 and TMU59 were 47% and 63%, respectively.

Experimental study on the effect of pressure decline rate on foamy oil flow characteristics in a heavy oil–CO2‐C3H8 system

AbstractCO2‐based cyclic solvent injection (CSI) processes have gained great interest and have been piloted to enhance heavy oil recovery sustainably. Although the performance of pure CO2 injection is encouraging, it is still not commercially feasible. In order to improve the performance of the CSI process, CO2 (72%) and C3H8 (28%) were chosen to be mixed with a heavy oil sample, and then four pressure depletion tests were conducted to investigate the effects of decline rates on the enhanced oil recovery performance and foamy oil flow behaviour. The production behaviour can be divided into three phases: volume expansion production phase (7% contribution), foamy oil flow production phase (73% contribution), and solution‐gas drive phase (20% contribution). The experimental results showed that depletion rates positively correlated with oil recovery factors in the last two phases. Additionally, the foamy oil flow phase was further divided into two zones: Zone‐1 (bubble nucleation and growth dominant zone) and Zone‐2 (bubble coalescence and disengagement dominant zone). The results showed that higher pressure depletion rates lead to larger pressure differences which in turn resulted in an increasing bubble nucleation rate in Zone‐1. While coalesced bubbles in Zone‐2 lead to a stronger discontinuous gas flow and the relative permeability of the oil phase decreased sharply. Compared with relatively lower heavy oil recovery factors (19.4%) in pure heavy oil–CO2 system, the heavy oil–CO2‐C3H8 system took advantage of a higher oil recovery factor (23.44%). Furthermore, the relatively lower average gas recovery factor and cumulative gas–oil ratio (cGOR) indicated that CO2 can be sequested in heavy oil reservoirs more efficiently.

Oil-recovery performance of a sponge-covered drum skimmer

Oil spill recovery by means of a rotating drum skimmer covered with a sponge layer was investigated experimentally for a wide range of operating conditions. Tests were conducted on two drums of diameters D = 300 mm and D = 200 mm and lengths L = 300 mm and L = 455 mm, respectively. The examined operating conditions encompassed oil viscosity, rotational speed, slick thickness and centre height above the oil/water interface. The results indicate the superiority of the sponge covered surface in oil recovery over the standard steel surface regardless of the viscosity of oil collected. The sponge-covered drum collected 24% more oil than the plain steel drum, when both were operated under the same conditions. The porous cover improves the skimmer performance due to its ability to absorb oil. The increase in oil slick thickness from 10 to 25 mm led to enhanced recovery rate by 59% in case of sponge-covered drum compared to17.5% with plain steel drum. The study paves the way to applying different types of porous sorbent materials to cover the oleophilic skimmers to achieve higher efficiency and oil recovery rate.

Enhanced oil recovery performance and mechanism of a wormlike micelles flooding system with zwitterionic-anionic surfactants

Surfactant-based wormlike micelles (WLMs) have been proven to be efficient in improving oil recovery due to their high viscosity and low oil/water interfacial tension (IFT). In this study, a novel WLMs oil displacement system was developed by mixing zwitterionic surfactant (Erucylamido propyl betaine, EAPB) and anionic surfactant (Sodium dodecylsulfate, SDS) at the mass ratio of 1.5:1. The viscosity, IFT and emulsification properties were studied by rheometry, interfacial tensiometry and bottle testing, respectively. The core and etched glass micro-model oil displacement tests were conducted to investigate the oil recovery efficiencies and the related mechanism. The results show that the EAPB-SDS combination system exhibits shear thickening compared to that of sole EAPB system due to the electrostatic attraction between SDS and EAPB. The viscosity is first increased and then decreased with the increase in pH, temperature and salinity. The IFT is decreased with pH, while it is first decreased and then increased with the increase of temperature and salinity. The EAPB-SDS combination system with mass concentration of 0.3% can enhance oil recovery by 25.91% and 19.79% after water flooding in homogeneous and heterogeneous cores, respectively. The high viscosity makes the system to exhibit good mobility control ability, while the low IFT contributes to the peeling and emulsification of residual oil, thereby significantly improving the oil displacement performance.

Permeability and heterogeneity adaptability of surfactant-alternating-gas foam for recovering oil from low-permeability reservoirs

As the traditional polymer stabilizer is eliminated to improve the injectability of foam in low-permeability reservoirs, the stability, plugging capacity, conformance control and oil recovery performance of the surfactant-alternating-gas (SAG) foam become significantly important for determining its adaptability to permeability and heterogeneity, which were focused and experimentally researched in this paper. Results show that the SAG bubbles are highly stable in micron-sized channels and porous media (than in the conventional unconstrained graduated cylinder), making it possible to use in enhanced oil recovery (EOR). Such bubbles formed in porous media could be passively adjusted to match their diameter with the size of the pore. This endows the SAG foam with underlying excellent injectability and deep migration capacity. Permeability adaptability results indicate a reduced plugging capacity, but, increased incremental oil recovery by the SAG foam with decreased permeability. This makes it a good candidate for EOR over a wide range of permeability, however, parallel core floods demonstrate that there is a limiting heterogeneity for SAG application, which is determined to be a permeability contrast of 12.0 (for a reservoir containing oil of 9.9 mPa s). Beyond this limit, the foam would become ineffective.

Laboratory comparison of tertiary N2, CH4, and CO2 injection into an Inland oil field sample

Few laboratory studies compared tertiary gas injection using N2, CH4, and CO2. However, these studies only focussed on oil recovery without examining CO2 storage. This study experimentally compares the oil recovery performance of tertiary N2, CH4, and CO2 injection into a composite Hutton Sandstone core taken from the Inland oil field, Australia. CO2 storage during tertiary CO2 injection is recorded. The core receives an initial injection, which is oil; then a secondary injection, which is water; and finally a tertiary injection, which is N2, CH4, or CO2. Pressure difference across the core and fluid production are recorded. Compositional analysis is performed on the produced oil samples. To estimate oil saturation distribution in the core, numerical simulations are run to simulate the injection experiment.Tertiary oil recovery for CO2 injection is found to be 23.1% of the original oil in-place, which far exceeds the 7.3% for CH4 injection and 5.3% for N2 injection. Ultimate oil recovery was 76.5% for tertiary CO2 injection, 59.6% for tertiary CH4 injection, and 58.3% for tertiary N2 injection. We observed that tertiary oil recovery for each injected gas begins with the oil bank it has generated being produced at a reasonably constant rate after which, the production rate declines reflecting the declining oil concentration in the oil bank. For tertiary CO2 injection, mass transfer between oil and CO2 is observed, which is found to lead to more production of the lighter oil after the oil bank production stage. In addition, tertiary CO2 injection is found to store 0.57 pore volume of the injected CO2 in the core.