EOR Potential Research Articles

Enhanced oil recovery in tight reservoirs by ultrasonic-assisted CO2 flooding: Experimental study and molecular dynamics simulation

CO2-enhanced oil recovery (CO2-EOR) has attracted great attention due to its dual effects of geological carbon storage and economic benefits, but the clay swelling, asphaltene deposition and gas channeling induced by CO2 still restrict its field application. The employment of chemical agents for the purpose of improving CO2-EOR performance is often limited by the heterogeneity of reservoirs and the potential for formation damage. Physical methods, such as ultrasonic-assisted CO2 flooding, appear to offer a promising alternative for CO2-EOR and geological sequestration. This study has conducted oil displacement experiments to investigate the EOR potential of ultrasonic-assisted CO2 flooding in tight reservoirs and clarify the effects of different ultrasound parameters. The ultrasonic waves with 20 kHz of acoustic frequency, 30 W/cm2 of sound intensity, 30 min of sonication time and moderate intermittent working mode can yield violent cavitation effects and avoid undesirable energy dissipation. Nearly a quarter of the saturated crude oil can be recovered from the tight core through ultrasonic-assisted CO2 flooding. It can be attributed to the composition alterations of crude oil and property changes of core matrix. Coupling with ultrasonic waves, CO2 would extract and vaporize crude oil more easily, which promotes oil swelling, lowers oil density and viscosity, decreases oil–gas interfacial tension and thus improves oil recovery. Besides, the ultrasound can help to mitigate the impact of CO2 adsorption-induced clay swelling on pore sizes through fluctuating pressure. And the strong hydrodynamic shear forces generated by mechanical vibration of ultrasound may also help to connect individual small pores and extend micro-fractures. These synergistic effects result in the transformation of micropores into mesopores and macropores. Furthermore, the wettability alteration of core samples implies that the ultrasonic-assisted CO2 flooding can induce the detachment of oil films from the rock surface. Finally, the results of molecular dynamics simulations indicate that the improvement in pressure inside the core sample resulting from ultrasonic cavitation facilitates the mixing of CO2 and oil, thereby weakening gas channeling and improving the displacement efficiency.

Experimental Investigations and MD Simulation on Nanoparticle-Enhanced CO2-Responsive Foam (NECRF): Implications on CO2-EOR.

CO2-responsive foam (CRF) is a highly promising candidate for CO2-enhanced oil recovery (CO2-EOR) because it displays higher stability than the surfactant-stabilized foam owing to the formation of robust wormlike micelles (WLMs) upon exposure to CO2. In this work, the nanoparticle-enhanced CO2-responsive foam (NECRF) was properly prepared using lauryl ether sulfate sodium (LES)/diethylenetriamine/nano-SiO2, and its interfacial properties and EOR potential were experimentally and numerically assessed, aiming to explore the feasibility and effectiveness of NECRF as a novel CO2-EOR technique. It was found that the interfacial expansion elastic modulus increased 6-fold after CO2 stimulation. The modulus continued to increase with the introduction of nano-SiO2 owing to the pronounced synergistic effect of WLMs and nanoparticles. In addition to increasing the viscosity of the foaming liquid, WLMs and nano-SiO2 enhanced the shearing resistance of the NECRF as well. Calculations demonstrated that both the coarsening rate and the size distribution uniformity coefficient of NECRF were markedly lower than that of the LES foam, which subsequently inhibited NECRF decay and greatly improved its dynamic stability. Besides, molecular dynamics simulation revealed that adding inorganic salts to NECRF could notably enhance the foaming performance due to the intensified hydration of surfactant head groups and reduced binding energy of neighboring molecules. Nuclear magnetic resonance-assisted core flooding experiments validated the exceptional capacity of NECRF to sweep the low-permeability region and improve the conformance profile. Overall, these findings may provide valuable insights into the development and application of novel materials and strategies for the CO2-EOR.

FORMULATING AND CHARACTERIZING AN OIL-IN-WATER PALM OIL FREE FATTY ACID-BASED NANOEMULSIONS FOR CRUDE OIL EXTRACTION PERFORMANCE

Nanoemulsion is a promising medium for chemically enhanced oil recovery (cEOR) due to its ability to reduce interfacial tension and modify the wettability of reservoir rocks. This work focuses on formulating stable oil-in-water (O/W) nanoemulsions through high-energy ultrasonication method, with oleic acid as the primary component and is stabilized with a non-ionic Tween 40 surfactant in distilled water. Systematic experimental designs, employing response surface methodology (RSM), were implemented to develop polynomial models for various responses related to the dynamic and stability properties, and crude oil extraction performance. The p-value indicator (p-value < 0.05) is utilized to assess the significance of the models and independent variables. Overall, the formulation for achieving the lowest surface tension involves 0.41 wt.% oleic acid mixed with 0.81 wt.% Tween 40 at 60 °C. Meanwhile, the highest viscosity attained with 1.0 wt.% oleic acid mixed with 1.0 wt.% Tween 40 at 30 °C. For stable nanoemulsion, the best conditions are 1.69 wt.% oleic acid, sonicated for 15 minutes at 25 °C. Additionally, an optimal condition for effective crude oil extraction is at nanoemulsion preparation with sonication time of 15 minutes and contact time of 12 hours in the immersion experiment. To this end, this work contributes valuable insights into the formulation and characterization of stable oleic acid O/W nanoemulsions for potential EOR applications. The findings enhance understanding of nanoemulsion properties and their potential as effective agents in crude oil recovery.

Synergistic study of xanthan-gum based nano-composite on PELS anionic surfactant performance, and mechanism in porous media: Microfluidic & carbonate system

Rising global energy demand and decrease in world fossil fuels reserves draw attention toward production from trapped oil in the reservoirs. CEOR methods are proved and efficient methods which can be applied for increased oil recovery. In this research, the EOR potential of a novel nanocomposite and a developed surfactant was evaluated in the presence of various ions and the production enhancement mechanisms were studied using glass micromodel. Primary, the synergistic effect of the nanocomposite and the natural surfactant on Interfacial tension (IFT) reduction and wettability alteration was studied. After quantitative analysis and investigation of the various mechanisms, it was understood that the presence of the nanocomposite in the surfactant solution alters the wettability of an oil-wet carbonate surface to a water-wet one. Adding nano-composite to surfactant solution can improve the wettability alteration ability of the surfactant up to 60.02%. The adsorption tests revealed that combining the nanocomposite with surfactant solution can reduce surfactant adsorption by 18.99 %. The Zeta potential test was utilized to evaluate the stability of the solution. The zeta potential of the nano/surfactant solution was equal to −28 which illustrated a stable solution. In addition, the zeta potential measurements demonstrated the wettability alteration mechanism. After investigating the properties of the nano-surfactant solutions in the presence of different ions, optimum concentrations were determined and the mechanisms of the nano-chemical EOR method were visually investigated by injecting the desired solutions into the glass micromodel. Eventually, five different injection scenarios were designed for the core flood tests to evaluate the performance of each solution in the porous medium. The achieved final recovery for PELS, PELS/NaCl, and PELS/NaCl/NC solutions were 48.05%, 55.62%, and 60.38%, respectively and the Alternative injection scenario was the best injection plan.

A study of the oil recovery potential and mechanisms of an alternative Alkaline-Surfactant-Polymer formulation for carbonate reservoir

Despite the promising nature of alkali-surfactant-polymer (ASP) flooding, its application is associated with various limitations that yield economic uncertainties about ASP projects. These limitations are aggravated in carbonate reservoirs where prevailing reservoir conditions attenuate the performance of various chemical agents in enhancing oil recovery. The goal of mitigating the impact of these limitations has led to research into the oil recovery potential of alternative chemical agents. Nevertheless, the literature has not reported a ternary combination of these alternative chemical agents. Therefore, this study focuses on investigating the potential of alternative ASP formulations composed of monoethanolamine (ETA), hexadecyl-3-methyl imidazolium bromide (C16mimBr), and Schizophyllan (SPG) for their enhanced oil recovery in carbonate reservoirs at high temperature (80 °C) and high salinity (4100 ppm) conditions. A conventional ASP formulation is deployed for comparative purposes. The current study is a sequel to our study on the oil recovery potential of an alkali-surfactant (AS) formulation made of ETA and C16mimBr. A comprehensive approach has been deployed to study the EOR potential of the proposed formulation. The approach included rheological measurements, core flood experiments, and micromodel experiments. The combination of ETA and SPG alleviates the detrimental effect of inorganic alkalis on HPAM. Therefore, the alternative ASP formulations showed better rheological properties than their conventional counterparts in bulk phase and porous media. The ETA–C16mimBr–SPG formulation also exhibited excellent EOR potential by recovering ∼27.05% additional oil, while the conventional counterpart achieved an additional oil recovery of ∼19.24%. Based on the results of the micromodel experiments, direct pore-to-pore displacement and emulsification are the main oil recovery mechanisms, and their occurrence depends on prevailing reservoir conditions. The study also confirms that wettability alteration as an oil recovery mechanism is more effective when the headgroup charge of the surfactant is the same as the surface charge of the rock. This study, therefore, reveals that a combination of organic alkali, surface-active ionic liquid, and biopolymer has excellent potential in enhancing oil recovery in carbonate reservoirs at high salinity–high-temperature conditions.

Adaptability and enhanced oil recovery performance of surfactant–polymer flooding in inverted seven-spot well pattern

As one of the leading technologies for chemical enhanced oil recovery (cEOR), surfactant–polymer (SP) flooding technology has long attracted the interest of petroleum scientists and engineers. However, most of its application scenarios are based on the five-spot well pattern. The EOR potential in an inverted seven-spot well pattern is seldom ever recorded. The applicability of the SP system in the inverted seven-spot well pattern was examined based on the physical characteristics of Karamay Oilfield in China. The numerical simulation and the one-dimensional core flooding experiment were used to compare the sweep intensities and EOR abilities of the two well patterns. The migration law and the EOR ability of the SP system were assessed by a specially made one-third inverted seven-spot configuration. The main controlling factors and compatibility charts of SP flooding development in the inverted seven-spot well pattern were obtained. Results show that 61% of the region is represented by a weak swept state in the inverted seven-spot well pattern. The effective swept area is greatly increased by appropriately raising the viscosity and slug size of the SP system. Compared to constant viscosity injection, step-down viscosity injection further increases the sweep range and oil recovery. The inverted seven-spot well pattern has a greater swept area of the SP system than the five-spot one, but a weaker strength. Polymer concentration is the most effective factor of SP flooding in the inverted seven-spot well pattern, followed by oil viscosity and surfactant concentration. The study can broaden the application of the SP system in the inverted seven-spot well pattern.

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.

Carbonated Smart Water Injection for Optimized Oil Recovery in Chalk at High Temperature

Finding cost-efficient ways of increasing oil production with a low carbon footprint is the new challenge for the petroleum industry that wants to meet the net-zero emission goals by 2050. Smart water injection is an EOR process that increases oil production and delays water breakthrough by wettability alteration. Seawater is a smart water in chalk reservoirs, being especially effective at high temperatures. Different studies have shown that the effectiveness of seawater can be further improved by modifying the ion composition before injection. Carbonated water (CW) has been proposed as a potential EOR fluid. In addition to producing extra oil, the reduction of greenhouse gas (CO2) in the atmosphere can be achieved by using carbonated smart water as an injection fluid. The main mechanism behind increased oil recovery by injecting carbonated water is believed to be oil viscosity reduction and swelling, as the CO2 is transferred from the aqueous phase to the oil phase. Wettability alteration has also been proposed as a possible mechanism, and this hypothesis is further investigated in this study along with other proposed mechanisms. Stevns Klint outcrop chalk was used in this study, this material is recognized as an excellent analogue for North Sea chalk reservoirs. Optimized oil recovery by carbonated water in chalk was investigated at a high temperature (130°C) by flooding carbonated formation water (CFW) and carbonated seawater (CSW), to be compared with high saline formation water (FW) and seawater (SW) flooding. The oil/brine/rock/CO2 interactions were tracked by measuring the pH of the produced water (PW) and by identifying any mineralogical changes by SEM (Scanning Electron Microscope) and EDX (Energy Dispersive X-Ray) analyses. The solubility of CO2 in different brines was measured and compared with simulation data performed by PHREEQC. The diffusion of CO2 from the aqueous phase to the oil phase was analysed to check if enough CO2 can be diffused from the carbonated water into the oil phase. By flooding CSW in both secondary and tertiary modes, a slight increase in the oil recovery was observed and was found to be the best performing brine. The oil recovery was also slightly increased using CFW in tertiary mode after FW which does not behave like smart water for carbonates. The solubility of CO2 was low and increased by increasing pressure and decreasing brine salinity. The acidity of CW did not increase by increasing pressure. No changes in pore surface minerals were observed after CW flooding, confirming limited mineral dissolution. A mass transfer of CO2 from the brine phase to the oil phase was confirmed in the experimental work, but a significant amount of CO2 remained in the brine phase. The main mechanism behind this extra oil observed using CW is most likely not linked to oil swelling and viscosity reduction or mineral dissolution which could affect the porosity and the permeability of the rock system. Wettability alteration is a more likely explanation but needs to be looked further into for confirmation.

Research and Application Progress of Wet-Phase Modified Expandable Graphite as a Steam Plugging Agent in Heavy Oil Reservoirs

Wet-phase modified expandable graphite (WMEG) particles have been successfully developed for in-depth steam channeling control in heavy oil reservoirs. WMEG particles can expand 4 to 7 times in a wet-phase environment and form a worm-like structure at steam temperature. The sand-pack flowing experiments demonstrated that WMEG particles have good injection, steam erosion resistance, and selective plugging capacity characteristics. By directly plugging and bridge plugging after expansion, WMEG particles can effectively plug steam channels. This paper also analyzes the EOR potential of WMEG particles through oil displacement experiments, proving that WMEG particles can further enhance oil recovery of heavy oil reservoirs. To better explain the steam plugging mechanism, the energy changes during WMEG particle expansion were also analyzed. The release of gas at different stages is the source of energy for WMEG particle expansion. WMEG particles have been successfully applied to 12 wells of four typical heavy oilfields in China. The results from these applications confirm that the injection of WMEG particles is an effective steam channeling control treatment. The success of these oilfield tests can also serve as a reference for similar steam injection heavy oilfields.

Laboratory to field scale assessment for EOR applicability in tight oil reservoirs

Tight oil reservoirs are contributing a major role to fulfill the overall crude oil needs, especially in the US. However, the dilemma is their ultra-tight permeability and an uneconomically short-lived primary recovery factor. Therefore, the application of EOR in the early reservoir development phase is considered effective for fast-paced and economical tight oil recovery. To achieve these objectives, it is imperative to determine the optimum EOR potential and the best-suited EOR application for every individual tight oil reservoir to maximize its ultimate recovery factor. Since most of the tight oil reservoirs are found in wide spatial source rock with complex and compacted pores and poor geophysical properties yet they hold high saturation of good quality oil and therefore, every single percent increase in oil recovery from such huge reservoirs potentially provide an additional million barrels of oil. Hence, the EOR application in such reservoirs is quite essential. However, the physical understanding of EOR applications in different circumstances from laboratory to field scale is the key to success and similarly, the fundamental physical concepts of fluid flow-dynamics under confinement conditions play an important role. This paper presents a detailed discussion on laboratory-based experimental achievements at micro-scale including fundamental concepts under confinement environment, physics-based numerical studies, and recent actual field piloting experiences based on the U.S. unconventional plays. The objective of this paper is to discuss all the critical reservoir rock and fluid properties and their contribution to reservoir development through massive multi-staged hydraulic fracture networks and the EOR applications. Especially the CO 2 and produced hydrocarbon gas injection through single well-based huff-n-puff operational constraints are discussed in detail both at micro and macro scale.

A comprehensive study on the application of a natural plant-based surfactant as a chemical enhanced oil recovery (CEOR) agent in the presence of different ions in carbonate reservoirs

Surfactant flooding is a promising CEOR approach in carbonate reservoirs and its efficiency has been verified. Commercial surfactants may impose various health and environmental issues. Therefore, utilizing a natural biodegradable surfactant at a low cost is a valuable option for the petroleum industry. In this research, a non-ionic surfactant derived from Acanthophyllum Plant Root Extract (APRE) was used as a bio-surfactant. The EOR potential of this surfactant was evaluated through various tests. Oil-water system interfacial tension (IFT) measurement, contact angle test for carbonate rock wettability alteration assessment, emulsion stability, compatibility, and surfactant flooding test were conducted. The effect of different ions of various salts on the IFT, carbonate rock wettability and the chemical interactions were also studied. The emulsion stability created by the surfactant was assessed through observational tests. The compatibility test (at 25 °C) showed that negligible sediment below the salinity of 50,000 ppm was formed. The IFT at CMC in formation water (optimum concentration of 12000 ppm) was reduced to 1.06 mN/m from an initial value of 2.16 mN/m. The optimum IFT value at different salinities was also determined. The wettability of the carbonate rock from a strongly oil-wet state (168°) was altered to water-wet (60.3°) in the presence of surfactant and FW with a concertation of 10,000 ppm. In the core flood test, the effect of different slug sizes and soaking time was also determined. It was observed that increasing slug size results in a lower mobility ratio and consequently higher oil recovery.

Toward evaluation and screening of the enhanced oil recovery scenarios for low permeability reservoirs using statistical and machine learning techniques

The concurrence of the oil demand increment and running out of fossil fuels have brought about special attention toward the tight and low permeability reservoirs. The decision-making regarding the most appropriate EOR approach suiting these target zones is not straightforward and may be associated with more sophistication than the conventional high permeability alternatives. This fact justifies the attempt to take a closer look at the outcomes of the EOR scenarios that have been implemented in the analogous oilfields. This is where the current study lies. This piece of study provides a rich databank with the hope to shed light on the potential EOR scenarios for the onshore/offshore low permeability reservoirs. The databank that embeds over 320 projects from about 218 oilfields situated in 16 worldwide countries is manipulated for two purposes: (1) evaluating the IOR projects in the worldwide low permeability onshore/offshore oilfields and (2) initiating various EOR screening tools based on the statistical plots, ensemble learning algorithms of Random Forest (RF), Gradient boosting Machine (GBM), and Extreme Gradient boosting (XGBoost), and the evolutionary algorithm of Gene Expression Programming (GEP). Comprehensive investigation and statistical analysis are conducted on the range of important parameters that can affect the EOR screening in this databank. Seven screening criteria of permeability, porosity, API, viscosity, lithology, depth, and temperature were considered for this purpose. The evaluation has demonstrated that the gas-based scenarios have the most contribution to the EOR projects of the world's onshore and offshore oilfields, respectively. Furthermore, the generated EOR screening tools have established themselves as valuable tools for the scope of this study. Among the AI-based approaches, the RF outperformed the alternatives with the training and test accuracies of 0.99 and 0.90, respectively. In the end, the achieved knowledge and the developed screening tools are used in a case study for elucidating the potential EOR scenarios for a given oilfield.

Surfactant formulation for Green Enhanced Oil Recovery

While the world continues to rely heavily on petroleum as a primary energy source, a great fraction of the oil-in-place remains inaccessible to traditional recovery means (thermal, gas, or chemical), posing significant environmental consequences and high treatment costs. Green enhanced oil recovery (GEOR) technologies, on the other hand, have generated interest in energy research as it involves the injection of specialized green fluids into reservoirs to improve sweep efficiency while also increasing residual oil production. Surfactant flooding, for example, has emerged as a viable green chemical EOR approach in which bioproducts produced by microbial metabolic processes are introduced into the reservoir to increase oil production These green surfactants (e.g., rhamnolipid, alkyl polyglycoside (APG), and lecithin) are now being studied for their possible uses in EOR processes as they have not been completely explored for their potential in chemical EOR. Therefore, in this study, a blend of rhamnolipid, APG, and lecithin are considered possible formulations to investigate the efficacy of these green surfactants in sandstone reservoirs based on phase behavior studies, interfacial tension measurement, and core-flooding experiments. It was found that all three blends (RB, RAB, and RL) performed well in the phase behavior study, resulting in stable middle phase microemulsions whereas only formulation RL had an ultralow IFT reduction between oil and brine. Consequently, this formulation (RL) performed the best of the three, with a tertiary recovery of 24% and a total recovery of approximately 70%. These results suggest that while other blends (RB and RAB) had good EOR potential, the third formulation (RL) is considered a more appropriate candidate for chemical EOR with a preference for biosurfactants (rhamnolipids) application. The outcomes of this study can aid in a better understanding of injection design methods and biosurfactant formulation selection, which is a critical attribute for green EOR technology.

The synthesis of novel amphiphilic GOJS-Cn nanoparticles and their further application in stabilizing pickering emulsion and enhancing oil recovery

Mixed nanoparticle stabilized Pickering emulsion is a novel research topic, which has been attracted more attention. In the present study, the novel amphiphilic GO-Janus SiO2-Cn nanoparticles (GOJS-Cn, n represents the number of carbon atoms in the modified alkyl chain) were successfully fabricated for the first time and investigated their ability in stabilizing Pickering emulsions for enhancing oil recovery. Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), and X-ray photoelectron spectroscopy (XPS) were employed to determine the successful fabrication of the GOJS-Cn. The optical microscopy was utilized to directly observe the GOJS-Cn (n = 0, 3, 8, and 12) stabilized emulsions and the static multiple light scattering was employed to further evaluate its stability quantitatively. It was found that the GOJS-C12 displayed the greatest ability to stabilize emulsions, even in high salinity (104 mg/L NaCl/MgCl2/CaCl2/AlCl3) and temperature (90 °C). Then, the interfacial tension, water contact angle, and dilatational measurements were conducted to reveal the mechanism of the GOJS-C12 superior emulsifying ability. The amphiphilic GOJS-C12 with great amphiphilicity spontaneously adsorbed at oil-water interface to promote the formation of rigid interfacial film, which was essential for the long-term stability of emulsion. Moreover, the core flooding tests reflected the GOJS-C12 stabilized emulsion could significantly enhance oil recovery (∼14.8%), then based on microscopic visualization experiments the potential EOR mechanism was proposed.

Carbon Capture And Storage (Ccs) - Enhanced Oil Recovery (Eor): Global Potential In Indonesia

Total global CO2 emissions from fossil-fuel will still increase in the next ten decades. These are attributed to the heavy reliance of human activities with fossil fuels. The uncontrolled CO2 emissions from combustion of fossil fuels cause the CO2 concentration alteration in the atmosphere. As the result, this phenomenon cause global warming and change the climate globally. In the future, CO2 emissions are predicted in range from 29 to 44 GtCO2/year in 2020. Therefore it is necessary to abate the CO2 missions to the level that would prevent dangerous anthropogenic interference to the global climate system. The growth of energy efficiency improvements, the switch to less-carbon intensive fuels and renewable resources employment is still low in the context CO2 emissions mitigation. Carbon Dioxide Capture and Storage (CCS) as a third option for these mitigation options might facilitate achieving CO2 missions stabilization goals. As a part of the commitment and participation on combating the global warming, Indonesia has signed the Kyoto Protocol in 1998 and ratified it in 2004 through Law No. 17/2004. On the other side, Indonesia oil production has been declining since in the last ten years but demand for this energy is still high. In this frame CCS-Enhanced Oil Recovery (EOR) by CO2 injection might answer the global warming challenges and alongside contribute to increase the oil production in the near future. This paper presents a preliminary study of CCS-EOR potential in Indonesia. A brief explanation of geological setting and reservoir screening for site selection also presented. Then some discussions about CCS-EOR global potential will be highlighted as well as the analysis. It is hoped that this study would provide a standard guideline for determining CCS- EOR potential in Indonesia.

Experimental study of spontaneous imbibition and CO2 huff and puff in shale oil reservoirs with NMR

The shale oil in the Jimsar sag, Junggar Basin, NW China is developed by horizontal wells and volume fracturing, and has the characteristics of a high initial production rate followed by a rapid decline and a low oil recovery factor. Therefore, it is necessary to find effective methods for enhancing shale oil recovery rates. The shale formations in the Jimsar sag, Junggar Basin are classified into three different types: types I, Ⅱ and Ⅲ. Fracturing fluid imbibition, surfactant imbibition and CO2 huff and puff experiments were conducted to evaluate the EOR potential of different types of shale formations. The oil distribution inside the shale core samples with time before, during and after the experiments is monitored using low-field NMR. The experimental results show that the CO2 huff and puff method had the highest ultimate oil recovery rate, followed by the surfactant imbibition method; the fracturing liquid imbibition method preformed without the addition of a surfactant had the lowest oil recovery rate. Surfactants improved the oil recovery of spontaneous imbibition by approximately 18% more in the type Ⅱ and Ⅲ shale formations compared to that of the fracturing liquid imbibition method. Field applications also demonstrated that adding a surfactant into the fracturing liquid significantly improved the oil production in type Ⅱ and Ⅲ oil formations relative to the common slick water fracturing liquid without an added surfactant.

Study on Fluid Behaviors of Foam-Assisted Nitrogen Flooding on a Three-Dimensional Visualized Fracture–Vuggy Model

Tahe Oilfield, located in northwest China, is an unconventional fracture–vuggy carbonate reservoir. The foam-assisted nitrogen gas flooding technology has been proven to be a potential EOR technology. However, the flow behaviors of foam-assisted nitrogen gas in fracture–vuggy structures are not clear due to the complex fracture–vuggy structures and their strong heterogeneity. In this work, a three-dimensional visualized fracture–vuggy model is designed and fabricated to investigate the fluids behaviors of foam-assisted N2 flooding and classify the residual oil types after foam-assisted N2 flooding. Experimental results reveal that foam slug can enlarge the sweep efficiency, suppress the formation of nitrogen gas channeling, and detach the oil film. Additionally, the evolution processes of the gas–oil and oil–water interfaces are investigated and analyzed. Moreover, the residual oil types after foam-assisted N2 flooding and nitrogen gas flooding, respectively, are classified and summarized. Compared to nitrogen gas flooding after water flooding, 12.36% more oil can be recovered through foam-assisted N2 flooding. This work further studies the fluid flow behaviors of foam-assisted N2 in the three-dimensional visualized fracture–vuggy carbonate model and also confirms the previous achievements.

The carbonic acid-rock reaction in feldspar/dolomite-rich tightsand and its impact on CO2-water relative permeability during geological carbon storage

CO2 injection contributes to formation energy supplement to remedy the fast production decline in tight oil reservoir and CO2 storage at the same time.CO2 Here, we report CO2-water relative permeability with consideration of acid-rock reaction. The minerals of a tight rock sample were analyzed at first. CO2Then we established an experimental method to measure the relative permeability of CO2-water at reservoir conditions based on steady state method. After carbonic acid-rock reaction, the variation in rock mineralogy was compared. The pore size distribution in the rock sample was obtained by LF-NMR after dynamic corrosion at different pressure. Both small and large pore and throat were enlarged after corrosion. And the Klinkenberg permeability of tight sandstone was increased 7.4–18.8%. From the CO2-water relative permeability with corrosion, the irreducible water saturation was decreased for more than 15.1% in average, which indicates more flowing spaces for other fluids. In the two-phase flow regime, a good linear relationship was found between Krw/Krg and gas saturation in tight sand samples. It can be used for the estimation of relative permeability at different gas conditions.CO2CO2 Injection of CO2 in tight oil reservoir indicates improvement in EOR and GCS potential. Acid-rock reaction results in better fluid flow capacity for liquid and additional trapping of CO2.

Migration and plugging characteristics of polymer microsphere and EOR potential in produced-water reinjection of offshore heavy oil reservoirs

Due to the strong heterogeneity, the infaust mobility ratio of offshore heavy oil reservoirs and the high cost of produced water treatment, a “green” in-depth profile control technology was proposed, which integrated produced water reinjection and microsphere in-depth profile control and displacement technology. Experimental results show that RGO-PMSs maintained to be spherical and expanded 5.2–6 time after aging 15 days in brine. While the size of RGO-PMSs aggregation increased 15–25 times, which induced the enhancement of plugging efficiency when permeability was higher than 3000 mD. During RGO-PMSs migration in porous media, it could adjust profile by adsorbing on rock surface or forming plugging in the forms of single capture, bridging, and accumulation. Due to the elastic deformation ability of RGO-PMSs, the particles could enter in-depth reservoirs to form plugging and modulate profile. Moreover, RGO-PMSs system injection and subsequent water flooding could enhance the oil recovery in high permeability layer and low permeability layer of 31.3% and 73.5%, respectively in parallels core displacement experiments. It is believed that the proposed produced water injection combined with RGO-PMSs could be a potential “green” candidate for enhancing oil recovery in offshore heavy oil reservoirs.

Novel preformed gel particles with controllable density and its implications for EOR in fractured-vuggy carbonated reservoirs

The pre-crosslinked gel particles has been perceived as an important alternative to improve oil recovery from fractured-vuggy carbonate reservoirs. However, it remains a great challenge for the applications in high temperature and high salinity reservoirs. In this context, we firstly developed novel preformed gel particles with controllable density (PGPCD) which can be used at high temperature (140 °C) and high salinity (250 g/L) fractured-vuggy carbonate reservoirs for in-depth profile control and displacement. Then, the swelling property, toughness, injectivity, EOR potential and EOR mechanisms of PGPCD were investigated. Experimental results show that PGPCD has favorable swelling ability, toughness, and controllable density due to the introduction of sodium montmorillonite and modified foamed acrylate rubber (ACM) powders. Moreover, PGPCD has favorable injectivity, and can mitigate water channeling in the form of “filling accumulation”, “bifurcation accumulation”, and “necked accumulation”. After the treatment, PGPCD achieves incremental oil recovery in a range of 16%–26% of original oil in place. Taken together, our findings suggest the role of PGPCD in promoting the incremental oil recovery at high temperature and high salinity reservoirs, especially in fractured-vuggy carbonate bottom water reservoirs.