Effective Enhanced Oil Recovery Research Articles

Synergistic enhancement of oil recovery: Integrating anionic-nonionic surfactant mixtures, SiO2 nanoparticles, and polymer solutions for optimized crude oil extraction

Enhanced oil recovery (EOR) methods are essential for optimizing oil extraction from modern reservoirs. This research delved into the synergistic impact of combining anionic and nonionic surfactant mixtures with silica (SiO2) nanoparticles (NPs) in sodium chloride (NaCl) solutions, alongside the added enhancement of polymers, to improve crude oil recovery. The study comprehensively evaluated stability, rheological characteristics, interfacial tension (IFT) behavior, wettability alterations, and EOR experiments using mixtures of sodium dodecyl sulfate (SDS) and triton X-100 (TX-100) surfactants. Scenarios both with and without SiO2 NPs in a base solution containing 3000 ppm NaCl and 2000 ppm xanthan gum (XG) polymer were examined. Core flooding tests were carried out on San-Saba sandstone core specimens with low permeability. The stability tests and dynamic light scattering (DLS) analysis were performed to assess the stability of NPs in low saline-surfactant-polymer solution. It was observed that NPs significantly reduced the IFT between the test solutions and crude oil, with nanofluids exhibiting satisfactory stability at a 0.4 wt% SiO2 NPs concentration. Core flooding studies demonstrated a synergistic interaction between NPs and the binary surfactant-polymer mixture, resulting in substantially greater incremental recovery of oil in comparison with the case of using binary surfactant-polymer combination alone. The mechanisms contributing to EOR with nanofluids, such as IFT reduction and wettability alteration, were explored. Incorporating NPs at concentrations of 0.1, 0.2, and 0.4 wt% led to incremental oil recoveries of 4.01 %, 12.35 %, and 12.73 % of the original oil in place (OOIP), respectively, as opposed to the recovery achieved using only SDS + TX-100 + XG. Consequently, these findings advance the understanding of the potential application of SiO2 NPs in combination with the binary surfactant-polymer mixture as effective chemical EOR agents. Additionally, these insights aid in identifying suitable sandstone reservoirs for nanofluid application, contributing to the optimization of oil recovery strategies.

Developing New Natural Surfactant from Date Seeds for Different Field Applications

The increase in using natural surfactants for enhanced oil recovery (EOR) purposes in recent years is mainly attributed to the widespread global awareness of the environmental effects the oil and gas industry causes. In accordance with KSA Vision 2030 and the corresponding global direction, the purpose of this study is to discover a cost effective, readily available, environmentally friendly, and locally sourced surfactant. This surfactant will help reduce the interfacial tension (IFT) between reservoir liquids to enhance the reservoir’s productivity and increase its ultimate recovery. In this study, date seeds have been chosen as the green surfactant source due to the abundance of such seeds. Al-Khalas, which is a well-known palm tree that grows in Qassim, Al-Kharj, and Al-Ahsa provinces in KSA was chosen. Properties such as surface tension (ST), IFT, pH, and density were measured to evaluate the effectiveness of date seeds as a natural surfactant. ST results showed a reduction from 72 mN/m (of distilled water) to 43 mN/m using the new surfactant in formation water at 10 wt% comprising a 40% reduction. Moreover, IFT of the new surfactant with Saudi medium oil (26 API) was 10 mN/m compared to 18 mN/m of a formation water-oil system which represents a 49% reduction in interfacial tension. Overall, the novel surfactant studied in this research shows great promise in being an effective EOR agent in addition to eliminating the negative impacts of regular surfactants on the environment.

Prospects and current state of chemical EOR methods applied in Kazakhstan

At present, at almost all fields of the Republic of Kazakhstan the main technology of oil recovery enhancement is the traditional method of waterflooding of productive formations. Many oil and gas fields in Kazakhstan are at a late stage of development and are categorized as «mature» fields. In the global experience of mature field development, the key focus is on the application of enhanced oil recovery (EOR) techniques - chemical, thermal, gas and microbiological methods. This paper considers the application of chemical EOR at a number of Kazakh fields such as Zaburunye, North Buzachi, Kalamkas, East Moldabek. As the results of the pilot studies have shown, the most effective EOR here is the application of polymer flooding. It should also be noted that polymer flooding is successfully applied in Kazakhstan for high-viscosity oil fields such as North Buzachi (oil viscosity 316-417 mPa·s), East Moldabek (oil viscosity 246-377 mPa·s). In this case, water cut, smoothing of injectivity profile and, as a result, increase of oil production is achieved. Successful application of the technology largely depends on the parameters of physical and chemical impact at each stage - the volume of injection of gel-polymer composition, concentration of ingredients, the flow rate of filtered water, the presence and linear size of cracks, the permeability of pore channels and etc. Polymer flooding applied in Kazakhstan showed its technological and economic efficiency on the example of pilot tests, laboratory studies, which reduces water cut and increases oil production. Widespread use of EOR methods would allow increasing recoverable oil reserves by at least 5-10 %. Keywords: Enhanced Oil Recovery (EOR); gas Injection; hydrocarbon recovery methods; chemical EOR methods; thermal EOR methods; oil production; polymer flooding; oil recovery.

Synthesis of temperature and salt resistance silicon dots for effective enhanced oil recovery in tight reservoir

The intensive development of tight reservoirs has positioned them as a strategic alternative to conventional oil and gas resources. Existing enhanced oil recovery (EOR) methods struggle to effectively exploring reservoir oil, resulting in low recovery rates. Novel and effective means of developing tight reservoirs are urgently needed. Nanomaterials have shown promising applications in improving water flooding efficiency, with in-depth research into mechanisms that lower injection pressure and increase water injection volumes. However, the extent of improvement remains limited. In this study, a silicon quantum dots (Si-QDs) material was synthesized via a hydrothermal synthesis method and used to prepare a nanofluid for the efficient recovery of tight reservoir. The Si-QDs, with an approximate diameter of 3 nm and a spherical structure, were surface functionalized with benzenesulfonic acid groups to enhance the performance. The developed nanofluid demonstrated stability without aggregation at 120 °C and a salinity of 60000 mg/L. Core flooding experiments have demonstrated the attractive EOR capabilities of Si-QDs, shedding light of the EOR mechanisms. Si-QDs effectively improve the wettability of rocks, enhancing the sweeping coefficient of injected fluids and expanding sweeping area. Within this sweeping region, Si-QDs efficiently stripping adsorbed oil from the matrix, thus increasing sweeping efficiency. Furthermore, Si-QDs could modify the state of pore-confined crude oil, breaking it down into smaller particles that are easier to displacement in subsequent stages. Si-QDs exhibit compelling EOR potential, positioning them as a promising approach for effectively developing tight oil reservoirs.

Wettability alteration of oil‐wet carbonate rocks by chitosan derivatives for application in enhanced oil recovery II: High‐temperature and high‐pressure conditions—Core flooding tests

AbstractBiopolymers, serving as Enhanced Oil Recovery (EOR) agents, are posing challenges and opportunities within the oil industry, particularly in demanding operational conditions. The assessment of trimethyl chitosan (TMC) and its hydrophobized derivative with myristoyl chloride (TMC‐C14) becomes crucial in these rigorous scenarios, presenting a significant challenge for polymer flooding. The study subjected TMC and TMC‐C14 to comprehensive evaluations as EOR agents, employing contact angle measurements, interfacial tension tests using the Drop Shape Analyzer (DSA), and core flood tests under conditions of 60°C, 1000 psi, and elevated salinity. Relative permeabilities were deduced from the results, while spontaneous imbibition tests provided insights into rock wettability. Amott cell tests underscored that both TMC and TMC‐C14 induced accelerated spontaneous oil production within a span of 30 days. Notably, TMC‐C14 exhibited superior interfacial activity compared to TMC, attributed to its hydrophobic segments. The impact on rock wettability was distinct: TMC shifted it towards water‐wet, while TMC‐C14 induced a neutral‐wet condition. This transformation was corroborated by contact angle measurements, imbibition tests, and relative permeability curves. Capillary forces, computed from DSA data and spontaneous imbibition tests, further validated the wettability‐altering tendencies of the chitosan derivatives on the rock. In core flooding tests and relative permeability curves, TMC demonstrated a notable improvement in the recovery factor (RF) compared to seawater. Specifically, RFTMC achieved 69%, surpassing RFbrine at 49%, affirming that the primary mechanism of action for chitosan derivatives lies in their ability to modify rock wettability. This study shows the potential of TMC and TMC‐C14 as effective EOR agents, shedding light on their interfacial activities, impact on rock wettability, and enhanced recovery factors in challenging operational conditions.

An efficient hybrid methodology for optimization of CO2 Huff-n-Puff EOR and sequestration in tight oil reservoirs

CO2 Huff-n-Puff is one of the effective enhanced oil recovery (EOR) methods in tight oil reservoirs, which is also attractive to sequestrating CO2 underground. Therefore, CO2 Huff-n-Puff EOR and sequestration project is particularly important both for oil and gas industry and environmental protection field. However, the technique has not gained industry-wide adoption partly due to knowledge gaps in efficient optimization of CO2 Huff-n-Puff EOR and sequestration using compositional numerical simulation. The purpose of this work is to propose an efficient hybrid optimization methodology which is called proxy-model-based optimization with initialization constraint. Two cases for single objective optimization and multi-objective co-optimization of CO2 Huff-n-Puff EOR and sequestration with two objective functions were investigated. Our findings suggest that the optimization performance of proxy-model-based optimization is highly dependent on the relative errors of the proxy model compared with simulator-based optimization. The optimization performance of proxy-model-based optimization with initialization constraint is 4∼10 % lower than that of simulator-based optimization, but the reduction in the number of simulations and improving the robustness of a stochastic optimizer are very attractive. In addition, different objective functions and optimization mode have different sensitive parameters. To the best of our knowledge, this is the first time to conduct single/multi-objective optimization of CO2 Huff-n-Puff EOR and sequestration in tight oil reservoirs based on numerical simulation technology, method of response surface experimental design and single/multi-objective particle swarm optimization algorithm. We believe the proposed methodology in this work is efficient especially for large reservoir simulations and rapid prediction of optimization schemes.

Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs.

CO2 flooding is a favorable technical means for the efficient development of low-permeability reservoirs, and it can also contribute to the realization of net-zero CO2 emissions. However, due to the unfavorable viscosity ratio and gravity overriding effect, CO2 channeling will inevitably occur, seriously affecting its storage and displacement effects. This paper conducts a systematic study on the application of polymer-assisted CO2 flooding in low-permeability reservoirs. Firstly, the polymer agent suitable for low-permeability reservoirs is optimized through the viscosity-increasing, rheological, and temperature- and salt-resistant properties of the solution. Then, the injectivity performance, resistance-increasing ability, and profile-improving effect of the polymer solution were evaluated through core experiments, and the optimum concentration was optimized. Finally, the enhanced oil recovery (EOR) effects of polymer-assisted and water-assisted CO2 flooding were compared. The results show that the temperature-resistant polymer surfactant (TRPS) has a certain viscosity-increasing performance, good temperature resistance performance, and can react with CO2 to increase the solution viscosity significantly. Meanwhile, TRPS has good injection performance and resistance-increasing effect. The resistance increasing factor (η and η') of TRPS-assisted CO2 flooding increases with increased permeability, the concentration of TRPS solution, and injection rounds. Considering η' and the profile improvement effect comprehensively, the application concentration of TRPS should be 1000 mg/L. The EOR effect of TRPS-assisted CO2 flooding is 8.21% higher than that of water-assisted CO2 flooding. The main effective period is in the first and second rounds, and the best injection round is three. The research content of this paper can provide data support for the field application of polymer-assisted CO2 flooding in low-permeability reservoirs.

Experimental investigation on supercritical multi-thermal fluid flooding using a novel 2-dimensional model

Supercritical multi-thermal fluid (SCMTF) is a promising alternative to traditional thermal agents for deep heavy oil recovery. However, no 2-dimensional experimental investigation on SCMTF flooding has been conducted due to the limitations of existing apparatuses. Therefore, the primary objective of this study is to develop a novel assembly for investigating the performance of SCMTF flooding. Subsequently, the SCMTF chamber evolution is characterized using newly developed equipment, and enhanced oil recovery (EOR) mechanisms are proposed. Finally, the effects of the injection temperature, injection pressure, scN2/scCO2 mixture, and heavy oil viscosity on SCMTF are comprehensively studied. The results show that the SCMTF chamber displays an inverted trapezoidal shape with a uniform front. SCMTF flooding can enhance heavy oil recovery by 13.36% relative to steam flooding by sweep area expansion, oil mobility improvement, and miscible flooding. Increasing the injection temperature, injection pressure or scN2/scCO2 mixture to SCW molar ratio can facilitate the production of heavy oil, while using SCMTF in an extra-heavy oil cannot maximize the EOR effect of SCMTF. Notably, the high yield of coke produced at elevated temperatures may lead to potential formation damage.

Designing effective enhanced oil recovery fluid: Combination of graphene oxide, D118 SuperPusher, and Chuback surfactant

Enhanced oil recovery (EOR) is one of the most essential branches of petroleum engineering and aims to maximize oil extraction from reservoirs. This research focuses on the utilization of graphene oxide (GO) in combination with a D118 SuperPusher compound and a natural surfactant (Chuback) to enhance oil recovery. The objective is to optimize the efficiency of the EOR process through a multi-component approach. The application of Chuback leads to a substantial decrease in interfacial tension (IFT), particularly in carbonate rock formations. This is attributed to the unique characteristics of carbonate rocks, which exhibit greater susceptibility to wettability alterations. Moreover, GO nanoparticles (NPs) were synthesized, then characterized and incorporated into the surfactant-polymer system, creating surfactant-polymer-nanoparticle (SPN) fluids. The selection of optimum fluid formulations for the EOR process is facilitated through the utilization of Design Expert, a statistical software tool. Factors such as surfactant concentration, polymer concentration, NPs concentration, and two types of salt concentrations are specifically chosen as variables that can influence the fluid's performance during the flooding step. Parameters including IFT, contact angle (CA) (which affects wetting behavior), and shear viscosity (which impacts fluid flow) are considered responses. The efficacy of the suggested fluid formulation for EOR is validated through core flooding investigations. Core flooding investigations validated the efficacy of the suggested fluid for EOR, with recovery factors of up to 30% and 56% in sandstone and carbonate core samples, respectively. These findings underscore the potential of the proposed approach to significantly enhance oil recovery from both sandstone and carbonate reservoirs.

Investigation of the Oil-Soluble Particulate Temporary Plugging Agent-Assisted Water Huff ‘n’ Puff Enhanced Oil Recovery in Tight Oil Reservoirs

Summary Water huff ‘n’ puff is an effective enhanced oil recovery (EOR) technology for tight oil reservoirs. However, the oil production of horizontal wells declines seriously after several huff ‘n’ puff cycles, and a large amount of oil is still trapped in the reservoir due to the heterogeneity of fracturing sections. The temporary plugging agent had been used for plugging high-permeability areas and thus diverting the following fluid into small permeability areas. It would improve the sweep efficiency of flooding fluid, enhancing oil recovery. However, the use of the oil-soluble particulate temporary plugging agent in the water huff ‘n’ puff application is barely reported. Therefore, the feasibility and influencing factors of oil-soluble particulate temporary plugging agent-assisted water huff ‘n’ puff (TAWHP) in enhancing oil recovery was investigated in this study. First, based on the evaluation of the performance of the oil-soluble particulate temporary plugging agent, the oil recovery of fractured core samples with different apertures for water huff ‘n’ puff and TAWHP was compared via the parallel-core experiment to verify the feasibility of TAWHP in enhancing oil recovery. The temporary plugging agent had good oil solubility, a low residual rate in the formation, and little damage to the formation. The oil recovery yielded by TAWHP was 5.17% higher than the traditional water huff ‘n’ puff process. More oil (i.e., about 1.71%) could be expelled from the fractured core samples with a small aperture. It indicated that the EOR performance yielded by water huff ‘n’ puff after several cycles could be enhanced by adding the oil-soluble particulate temporary plugging agent. After that, a mathematical model of TAWHP was established to investigate the effect of TAWHP parameters on EOR performance. The simulation results showed that the cumulative oil production increased with the increase in injection time of the temporary plugging agent solution, but the trend would level-off after 10 minutes. Moreover, as the diversion index increased, the effect of the injection rate on cumulative oil production gradually enhanced while the effect of the soaking time gradually weakened. Furthermore, the difference in cumulative oil production at different diversion indexes gradually increased as the huff ‘n’ puff cycle increased. This work could provide theoretical guidance for water huff ‘n’ puff enhancing oil recovery after several cycles.

Molecular dynamics investigation of DME assisted CO2 injection to enhance shale oil recovery in inorganic nanopores

In view of the unsatisfactory improvement effect of pure CO2 injection on the shale oil recovery in microscopic pores, the molecular dynamics method was used to simulate the process of dimethyl ether (DME) assisted CO2 injection in nanopore to recover shale oil. Firstly, cosolvents with different functional groups were selected to assist CO2 injection to compare the enhanced oil recovery (EOR) effect of shale oil. Subsequently, the microscopic mechanism of DME promoting CO2-EOR effect was systematically revealed. Then, the effects of temperature, pressure, DME molar content and shale oil composition on the EOR mechanism of CO2-DME mixture were further studied. Finally, the sensitivity difference of EOR effect to these influencing factors was compared. The research results showed that the EOR effect of DME-assisted CO2 injection (42.96%) is the best, followed by acetone (38.61%), propane (33.38%), ethanol (32.42%) and pure CO2 (22.43%). The microscopic EOR mechanism of DME-assisted CO2 injection includes improving the solubility and competitive adsorption capacity of CO2, as well as reducing oil viscosity and two-phase interfacial tension (IFT). The EOR effect of CO2-DME mixture is the best when the system temperature rises to 100℃, but excessive high temperature has a negative impact on CO2 solubility and intermolecular interaction. The increase of system pressure increases the fluid density, shortens the mass transfer distance, and reduces the IFT, which promotes the solubility, miscibility and competitive adsorption capacity of CO2-DME mixture, thereby continuously improving the shale oil recovery. Although the increase of DME content can improve the competitive adsorption capacity and reduce the IFT, it also reduces the solubility and diffusion capacity. The EOR effect is best when the mole fraction of DME reaches 40%. The increase of the proportion of non-hydrocarbon compounds and heavy hydrocarbon components reduces the solubility, miscibility and competitive adsorption capacity of CO2, and the negative impact of the former is greater than that of the latter. The EOR effect of DME-assisted CO2 injection on shale oil is most affected by pressure, followed by DME mole fraction, temperature, and oil composition.

Evolution Law of Dominant Flow Channel and Enhanced Oil Recovery Measures for Water Flooding in Reservoirs with Partially Sealed Faults.

The presence of strongly sealed faults can divide a reservoir into complex fault blocks, while partially sealed faults can be created by farewell faults within each block, leading to more intricate fluid migration and residual oil distribution. However, oilfields often overlook these partially sealed faults, focusing instead on the entire fault block, which can impact the efficiency of the production system. In addition, the current technology struggles to quantitatively describe the evolution of the dominant flow channel (DFC) during the water-flooding process, especially in reservoirs with partially sealed faults. This limits the ability to formulate effective enhanced oil recovery measures during the high water cut stage. To address these challenges, a large-scale sand model of a reservoir with a partially sealed fault was designed, and water flooding experiments were conducted. Based on the results of these experiments, a numerical inversion model was established. By combining percolation theory and the physical concept of DFC, a new method was proposed to quantitatively characterize DFC using a standardized flow quantity parameter. The evolution law of DFC was then studied, considering the variations of volume and oil saturation of DFC, and the water control effect of different measures was evaluated. The results revealed that, during the early stage of water flooding, a vertical uniform dominant seepage zone formed near the injector. As the water was injected, DFCs from the top of the injector to the bottom of the producers gradually formed in the unoccluded area. However, DFC was only formed at the bottom in the occluded area. During water flooding, the volume of DFC in each area gradually increased and then tended to stabilize. The development of the DFC in the occluded area lagged behind due to gravity and fault occlusion, leading to the formation of an unswept area near the fault in the unoccluded area. The volume of the DFC in the occluded area was the slowest, and the volume was the smallest after stabilization. Although the volume of the DFC near the fault in the unoccluded area grew the fastest, the volume was only higher than that in the occluded area after stabilization. During the high water cut period, the remaining oil was mainly distributed in the upper part of the occluded area, the area near the unoccluded fault, and the top of the reservoir in other areas. The plugging of the lower part of the producers can increase the volume of DFC in the occluded area, and the DFC moves up throughout the entire reservoir. This improves the utilization degree of the remaining oil at the top of the entire reservoir, but the remaining oil near the fault in the unoccluded area remains inaccessible. The combination of producer conversion, drilling infill wells, and producer plugging can alter the injection-production relationship and weaken the occlusion effect of the fault. The occluded area forms a new DFC, leading to a significant increase in the recovery degree. The deployment of infill wells near the fault in the unoccluded area can effectively control the area and improve the utilization of the remaining oil.

Effect of silica-based hybrid nano-surfactant on interfacial tension reduction for enhanced oil recovery

Crude oil production has considerably stabilized economic growth on a global scale. Unfortunately, the difficulties of oil production from a reservoir is being a global concern. Enhanced oil recovery (EOR) is one of the methods employed recently to increase oil production rate. Nanotechnology has been identified as one of the effective EOR techniques employed using nanoparticles (NPs) as a suitable candidates. Altering a reservoir's petrophysical property such as reducing interfacial tension (IFT) between crude oil and other liquids is an essential factor that plays a significant role in EOR. Considering the significant effects shown by silicon dioxide (SiO2) and iron dioxide (Fe2O3) NPs in EOR, the present study is aimed at investigating the influence of Fe2O3-SiO2 hybrid NPs supported with a surfactant on IFT. The hybrid NPs were produced and separately incorporated with surfactants of anionic sodium dodecylbenzene sulfonate (SDBS) and polyvinylpyrrolidone (PVP). The physical and chemical properties of the hybrid NPs were analyzed using X-ray diffraction (XRD) and Fourier transforms infrared (FTIR) spectroscopies, respectively. According to the results, the XRD pattern of the Fe2O3-SiO2 hybrid NPs displayed a crystalline structure of Fe2O3 NPs. The FTIR spectra of Fe2O3-SiO2 hybrid NPs showed characteristic absorptions of Fe2O3 and SiO2, indicating successful hybrid formation. The viscosity of Fe2O3-SiO2 nanofluids has increased from 0.95 to 1.85 cP. Upon introducing a hybrid nano-surface of SDBS and PVP, the viscosity values increased to 1.95 cP and 1.90 cP, respectively. Moreover, the Fe2O3-SiO2 hybrid NPs has reduced oil/brine/nanofluids IFT from 17.39 mN m−1 to 5.03 mN m−1. Additional reductions were observed when the surfactants were included. Consequently, IFT (mN m−1) was reduced from 17.39 to 3.08 for Fe2O3-SiO2-PVP and from 17.39 to 2.55 for Fe2O3-SiO2-SDBS. The finding of this study can help for a better understanding of the significant effect of silica-based hybrid nano-surfactant for IFT reduction which in turn could enhance oil production.

Polymer Screening for Efficient Water Cut Reduction in a Sandstone Oilfield in Kazakhstan.

Polymer flooding is one of the most widely used and effective enhanced oil recovery techniques. It can improve the macroscopic sweep efficiency of a reservoir by controlling the fractional flow of water. The applicability of polymer flooding for one of the sandstone fields in Kazakhstan was evaluated in this study and polymer screening was carried out to choose the most appropriate polymer among four hydrolyzed polyacrylamide polymer samples. Polymer samples were prepared in Caspian seawater (CSW) and assessed based on rheology, thermal stability, sensitivity to non-ionic materials and oxygen, and static adsorption. All the tests were performed at a reservoir temperature of 63 °C. Based on the results of the screening study, tolerance of a polymer towards high-temperature reservoir conditions, resistance to bacterial activity and dissolved oxygen present in make-up brine, chemical degradation, and reduced adsorption on rock surface were considered the most important screening parameters. As a result of this screening study, one out of four polymers was selected for the target field as it showed a negligible effect of bacterial activity on thermal stability. The results of static adsorption also showed 13-14% lower adsorption of the selected polymer compared to other polymers tested in the study. The results of this study demonstrate important screening criteria to be followed during polymer selection for an oilfield as the polymer should be selected based on not only polymer characteristics but also the polymer interactions with the ionic and non-ionic components of the make-up brine.

A Three-Phase Relative Permeability Model for Heavy Oil Emulsion System

Chemical flooding is important and effective enhanced oil recovery processes are applied to improve the recovery of heavy oil reservoirs. Emulsification occurs during chemical flooding processes, forming an oil-in-water (O/W) emulsion system. In this work, the heavy oil emulsion system is characterized as a three-phase (continuous oil phase, dispersed oil phase, and continuous water phase) system. Based on a capillary tube model, a new relative permeability model is proposed to describe the flow of the emulsion system in porous media quantitatively, considering the physicochemical properties of emulsions and the properties of porous media. A resistance factor is derived in this model to describe the additional resistance to the emulsion flow caused by the interaction between dispersed oil droplets and the pore system. Three dimensionless numbers related to the emulsion porous flow process were proposed and their different effects on the three-phase relative permeability are investigated. To validate the reliability of the proposed model, a one-dimensional O/W emulsion–oil displacement experiment is simulated. The maximum absolute error between the simulated results and experimental data is no more than 10%, and the new model can be used to describe the flow behavior of heavy oil emulsions in porous media.

A hybrid connectionist enhanced oil recovery model with real-time probabilistic risk assessment

An effective enhanced oil recovery (EOR) method requires an evidence-based, data-driven assessment of the impacts of the governing parameters on the rate of oil production. In this research, an innovative and comprehensive approach is developed to analyze the optimization of oil production by carbon dioxide (CO2) injection and associated risks as a function of time in a shale formation reservoir. The data-driven approach is used to perform risk analysis. This study integrates a commercial simulator with a deep learning network and probabilistic method to predict oil production enhancement with the associated risks. The integrated approach presented in this study creates evidence from the Spatio-temporal model based on geological data of the shale formation. The data-driven model uses the long short-term memory (LSTM) network to forecast oil production based on Spatio-temporal datasets. The possible risks are assessed using a dynamic Bayesian network with an early warning index system (EWIS) derived from the data-driven model. The findings of the Spatio-temporal model show that CO2 injection would lead to the maximum oil recovery rate of 22% of the original oil-in-place with associated risks in each cycle of operation. This study confirms that the introduced model can serve as a multifunctional tool for oil production optimization with a clear understanding of associated risks.

Assessment of CO2-Oil swelling behavior using molecular dynamics simulation: CO2 utilization and storage implication

CO2 injection into petroleum reservoirs is an effective enhanced oil recovery (EOR) method that can increase the recovery of oil while reducing CO2 emissions into the atmosphere. To ensure successful implementation of CO2 EOR, a detailed understanding of reservoir fluid properties and the phase behavior of CO2-oil mixtures at different scales is required. The extent to which CO2 injection improves the oil recovery factor is heavily dependent on the swelling behavior of CO2-oil mixtures, which can be quantified by swelling factors. In this study, we model a CO2-oil swelling test using molecular dynamics (MD) simulations to calculate the swelling factors over a pressure range of 24.8 to 68 bar at a temperature of 303.15 K for an actual crude oil sample. The multicomponent molecular model of the oil is built using 1000 molecules of six hydrocarbons, based on the compositional analysis of the oil sample. CO2 molecules are then added to the system at several pressure steps, based on experimental CO2 solubility data, and the resulting swelling factors are compared to their corresponding experimental values. The results of this study demonstrate that the MD simulation model can be successfully used to investigate CO2-oil swelling behavior and accurately predict the swelling factors with a minor mean percentage error of 6%. Additionally, analysis of potential energy variations due to interactions between different molecules in the system under increasing pressures and CO2 mole fractions indicates that the swelling process is primarily controlled by changes in intermolecular forces between CO2-oil and oil-oil molecular pairs, while the effect of CO2-CO2 molecular potentials on oil swelling is minimal. This work highlights the ability of the MD simulation technique to model the complex phase behavior of CO2-oil mixtures and provides unique insights into the molecular-scale mechanisms of CO2 dissolution in oil and the resulting swelling phenomenon.

A Review of Wettability Alteration by Spontaneous Imbibition Using Low-Salinity Water in Naturally Fractured Reservoirs

Analysis of fluid flow in naturally fractured reservoirs (NFRs), as a highly heterogeneous and complex system, requires a detailed study of the fracture-matrix interactions. The main process of fluid movement between the fracture and matrix is spontaneous imbibition (SI), which can occur in co/countercurrent fluid flow states. In addition, most carbonate rocks are fractured and non-water-wet, which can lead to low oil recovery. Wettability greatly affects the performance of the SI process. Injection of water or chemicals can be insufficient because fluids mostly pass through highly permeable fractures and lead to early breakthrough. Therefore, the wettability alteration mechanism should be applied in NFRs, and low-salinity water (LSW) injection is considered an effective enhanced oil recovery (EOR) approach. In this review, experimental and numerical studies of co/counter-imbibition are analyzed to show the importance of investigating the fracture-matrix interactions. In addition, the review shows the wettability effect on imbibition in fractured rocks. The review of experimental studies of LSW imbibition in fractured carbonates shows the possibilities for implementing an EOR method. However, the wettability alteration process during SI using LSW has not yet been studied, and no simulation models of co/countercurrent flows have yet been provided. Based on this review, more experimental studies are recommended to duplicate co/countercurrent imbibition using LSW. Advanced techniques such as CT scanning, MRI, and NTI can be used to reveal fluid distribution. Using experimental data, numerical models can be developed to characterize dynamic wettability alteration during co/countercurrent imbibition.

A numerical simulation investigation on low permeability reservoirs air flooding: Oxidation reaction models and factors

A precise oxidation reaction model determines the reliability of numerical simulation results and the prediction of field performance of air injection-based enhanced oil recovery (EOR). By reviewing the classical oxidation reaction model and combining with geological characteristics of a low permeability reservoir, this work creatively divides pseudo-components and temperature regions and further proposes the improved low temperature oxidation (LTO), middle temperature oxidation (MTO), and high temperature oxidation (HTO) numerical models with chemical reaction coefficients. The EOR effects of reservoir temperature, permeability, air flow rate and bottom hole pressure during LTO and full temperature regions are determined on the basis of a 3D reservoir simulation model via CMG STARS. The results show that peak oil production rates of N2 flooding and LTO are 17.70 and 29.97 m3/d, respectively. The cumulative oil production in LTO stage is about 35%, which is higher than that in N2 flooding. The oxygen addition reaction in LTO stage can release much heat and increase sweep efficiency from thermal expansion and viscosity reduction. The peak oil production rates of LTO and full temperature oxidation (FTO) reactions are 42.16 and 44.34 m3/d, respectively, and the cumulative oil production of the FTO model was about 17% higher than that of LTO. The FTO model could more truly reflect the production performance during air flooding of low permeability oil reservoir. Strong oxygen consumption capacity and significant heat release effects can be observed under higher initial temperature, permeability, air flow rate, and lower bottom hole pressure. Thermal flooding and flue gas flooding are the main EOR mechanisms in FTO process. Considering the inescapable field problem of gas channeling, thorough contact between oil and air can be promoted by artificially preheating oil reservoir and adjusting air injection rate and pressure. Thus, oil recovery can be further improved under the premise of ensuring the safety of field application of air flooding technique.

Study on the Lower Limits of Physical Parameters for Heavy Oil Reservoirs during the In Situ Combustion Process.

As an effective enhanced oil recovery (EOR) method in the late stage of the steam injection process, in situ combustion (ISC) has been verified by more and more researchers owing to its high recovery efficiency and low operation cost. However, the ISC process is prone to bringing about an unfavorable result with a low sweep efficiency and even an extinction process due to the complexity and uncertainty in oil and water distribution as well as the heterogeneity of the actual reservoir. In this work, combustion tube experiments combined with numerical simulations by CMG-STARS were conducted to study the influence of a reservoir's physical parameters on the stability of ISC. It was found that the sustainability of the combustion process is sensitive to permeability and oil saturation, the lower limits of which are determined as 0.2 μm2 and 0.2, respectively. Then, a formula was preliminarily proposed as 0.25 ≤ So/K ≤ 0.8, which could be used as a reference of screening criteria in designing the ISC process.