Enhanced Oil Recovery Performance Research Articles

Study on the mechanism of CO2 huff-n-puff enhanced oil recovery and storage in shale porous media considering heterogeneous structure

CO2 possesses several advantages, including strong solubility, effective viscosity reduction ability, and low miscible pressure, making it a promising candidate for enhanced oil recovery (EOR). Additionally, due to its adsorption capture mechanism, shale formations are considered ideal environments for CO2 storage. However, the influence of heterogeneity of shale multi-scale structure on CO2 migration mechanism, EOR, and storage mechanism is not clear. In this study, a heterogeneous shale structure model containing fractures and matrix was designed based on scanning electron microscope. The multiphase–multicomponent–multirelaxation model was used to study the fluid migration mechanism in the process of miscible CO2 huff-n-puff in shale reservoir. By analyzing density variations, velocity changes, and pressure distributions, the effects of diffusion coefficient, adsorption parameters, and fracture size were studied. Furthermore, by changing the matrix structure, the influence of heterogeneity on the law of oil and gas migration was explored. Additionally, a comparison between CO2 and water was performed. Finally, the influence of reservoir heterogeneity on fluid transport mechanism was studied. The results show that EOR and CO2 storage rate (CSR) are proportional to the diffusion coefficient. The main factor affecting the CSR is the adsorption capacity of rock to CO2. The larger CO2–oil contact area between the fracture and the matrix leads to a larger CSR, highlighting the importance of induced fractures. In addition, it was found that CO2 huff-n-puff was superior to water flooding, showing an EOR performance advantage of about 15%. This study is helpful for the practical application of CO2 huff-n-puff technology in the field of unconventional oil and gas development and CO2 storage.

Evaluation of the Thermal, Chemical, Mechanical, and Microbial Stability of New Nanohybrids Based on Carboxymethyl-Scleroglucan and Silica Nanoparticles for EOR Applications.

Scleroglucan (SG) is resistant to harsh reservoir conditions such as high temperature, high shear stresses, and the presence of chemical substances. However, it is susceptible to biological degradation because bacteria use SG as a source of energy and carbon. All degradation effects lead to viscosity loss of the SG solutions, affecting their performance as an enhanced oil recovery (EOR) polymer. Recent studies have shown that nanoparticles (NPs) can mitigate these degradative effects. For this reason, the EOR performance of two new nanohybrids (NH-A and NH-B) based on carboxymethyl-scleroglucan and amino-functionalized silica nanoparticles was studied. The susceptibility of these products to chemical, mechanical, and thermal degradation was evaluated following standard procedures (API RP 63), and the microbial degradation was assessed under reservoir-relevant conditions (1311 ppm and 100 °C) using a bottle test system. The results showed that the chemical reactions for the nanohybrids obtained modified the SG triple helix configuration, impacting its viscosifying power. However, the nanohybrid solutions retained their viscosity during thermal, mechanical, and chemical degradation experiments due to the formation of a tridimensional network between the nanoparticles (NPs) and the SG. Also, NH-A and NH-B solutions exhibited bacterial control because of steric hindrances caused by nanoparticle modifications to SG. This prevents extracellular glucanases from recognizing the site of catalysis, limiting free glucose availability and generating cell death due to substrate depletion. This study provides insights into the performance of these nanohybrids and promotes their application in reservoirs with harsh conditions.

Influence of viscosity ratio on enhanced oil recovery performance of anti-hydrolyzed polymer for high-temperature and high-salinity reservoir

The viscosity ratio of polymer and oil is a crucial factor for polymer flooding, which can affect the water–oil mobility ratio and oil recovery. However, for high-temperature and high-salinity reservoirs, the reasonable viscosity ratio limit of polymer flooding under the condition of medium–high permeability and low oil viscosity is not clear. Thus, the heterogeneous sand-pack flooding experiments were carried out to analyze the influence of polymer–oil viscosity ratio on the enhanced oil recovery (EOR) performance of anti-hydrolyzed polymer to establish a reasonable viscosity ratio limit. Then the three-dimensional heterogeneous model flooding experiments were performed to clarify the mechanism. The results showed that when the permeability ratio was the same, as the viscosity ratio increased from 0.15 to 2.0, the incremental oil recovery increased from 3.2% to 27.2%. When the viscosity ratio was the same, the incremental oil recovery decreased with the increase in the permeability ratio. The reasonable viscosity ratio ranges from 1.0 to 1.5. For three-dimensional heterogeneous model flooding experiments, as the polymer–oil viscosity ratio increased from 0.45 to 1.0, the swept area of high and low permeability area was expanded and the oil saturation near the injection well in the mainstream channel was greatly reduced. Moreover, when the polymer–oil viscosity ratio was 1, the difference in the width of the mainstream channels between high and low permeability layers in the saturation field decreased, and the degree of utilization in low permeability layers increased significantly. As the polymer–oil viscosity ratio increased from 0.45 to 1.0, the incremental oil recovery increased from 16.2% to 24%.

Development and performance evaluation of nonionic surfactant-stabilized nanoemulsion for enhanced oil recovery applications in tight reservoir

Nanoemulsions have garnered great attention as a chemical additive for enhanced oil recovery (EOR) technology worldwide due to their small size and unique physicochemical properties. Herein, this work introduces a novel nonionic surfactant-stabilized nanoemulsion prepared using a low-energy method for EOR projects in the Chang 8 tight reservoir. Spontaneous imbibition experiments were conducted in oil-saturated cores, and secondary imbibition experiments were carried out in water-bearing cores. Additionally, core flooding experiments were performed to study the EOR performance of both nanoemulsion and complex surfactant. Finally, the EOR mechanisms were thoroughly investigated, specifically focusing on oil-washing capacity, reduced interfacial tension, and wettability alteration. The designed nanoemulsion, with droplets averaging 10.5 ± 0.7 nm in synthetic formation brine at ambient temperature, exhibits excellent thermal and long-term stability even under reservoir temperature conditions. The oil recovery efficiency of the nanoemulsion system in oil-saturated cores through spontaneous imbibition was 31.28%, representing a 6.42% improvement over the complex surfactant solution. In the secondary imbibition experiments, the nanoemulsion mobilized 8.53% of the residual oil, compared to 4.11% for the complex surfactant. Core flooding experiments revealed that the nanoemulsion system achieved a total oil recovery of 62.69%, outperforming the complex surfactant system by 8.68% during the chemical flooding stage and 1.82% during the subsequent brine flooding stage. The EOR mechanisms of nanoemulsion in tight reservoirs can be attributed to four aspects: reduction of oil/water interfacial tension, wettability alteration, miscibility with crude oil, and increased sweep volume. The generation of the Marangoni effect and the adsorption and diffusion characteristics are essential differences between the nanoemulsion system and the complex surfactant system. The presented findings in this paper could aid in promoting the large-scale use of nanoemulsions in Chang 8 tight reservoirs.

Development of Novel Silicon Quantum Dots and Their Potential in Improving the Enhanced Oil Recovery of HPAM.

Hydrolyzed polyacrylamide (HPAM) is commonly used in polymer flooding, however, it is prone to viscosity reduction at high temperatures and high salinities, weakening its ability to improve oil recovery. In this work, sulfonated modified silicon quantum dots (S-SiQDs) were synthesized and then added to HPAM to study the improvement of rheological properties and enhanced oil recovery performance of HPAM at high temperatures and salinities. It is found that the S-SiQDs with a concentration of only 0.1 wt % can significantly increase the viscosity of HPAM from 28.5 to 39.6 mPa·s at 60 °C and 10,000 mg/L NaCl. Meanwhile, the HPAM/S-SiQDs hybrid solution always possessed higher viscosity and viscoelastic moduli than HPAM, attributed to the hydrogen bonding between HPAM and S-SiQDs. Notably, HPAM/S-SiQDs still maintained elastic behavior at harsh conditions, indicating that they formed a strong network structure. Through oil displacement experiments, it was found that the oil recovery of HPAM/S-SiQDs was higher (28.3%), while that of HPAM was only 17.2%. Thereafter, the utilization sequence of oil during the displacement process was studied with nuclear magnetic resonance experiments. Ultimately, the oil displacement mechanism of HPAM/S-SiQDs was deeply analyzed, including viscosity thickening and wetting reversal.

A review of mechanisms influencing stable rheology complex Pickering foams for carbon utilization & storage in subsurface formations

While CO2 foams have been utilized for tertiary oil recovery and carbon collection, utilization, and storage for quite some time, but due to foam instability, the storage efficiency and enhanced oil recovery (EOR) of this method have been less efficient. Pickering foam represents a complex fluid made of CO2 bubbles stabilized by nanoparticles in water (NPs). This approach considerably enhances EOR and CO2 storage performance. The various mechanisms influencing the stabilization of a foam by an NPs have also been discussed. As a CO2 foam enhancer, NPs improve the foam layer & interfacial dilatational viscoelasticity and dynamic CO2 storage. Incorporating NPs on the foam lamella inhibits foam bubble disintegration and enhances foam’s durability. The novelty of the work lies in the concise explanation of various mechanisms influencing the success of Pickering foams in this role. A stable CO2 foam when injected into a heterogeneous porous media causes a larger areal sweep, even under adverse shear conditions and regains initial rheological profile, once shear is withdrawn, and the improved CO2 storage contributed to a boost in sweep efficiency, enabling the collection of larger amounts of oil.

Experimental investigation into effects of the natural polymer and nanoclay particles on the EOR performance of chemical flooding in carbonate reservoirs

This paper aims to investigate the tragacanth gum potential as a natural polymer combined with natural clay mineral (montmorillonite, kaolinite, and illite) nanoparticles (NPs) to form NP–polymer suspension for enhanced oil recovery (EOR) in carbonate reservoirs. Thermal gravimetric analysis (TGA) tests were conducted initially in order to evaluate the properties of tragacanth gum. Subsequently, scanning electron microscopy (SEM) and energy-dispersive X-ray (EDX) tests were used to detect the structure of clay particles. In various scenarios, the effects of natural NPs and polymer on the wettability alteration, interfacial tension (IFT) reduction, viscosity improvement, and oil recovery were investigated through contact angle system, ring method, AntonPaar viscometer, and core flooding tests, respectively. The entire experiment was conducted at 25, 50, and 75 °C, respectively. According to the experimental results, the clay minerals alone did not have a significant effect on viscosity, but the addition of minerals to the polymer solution leads to the viscosity enhancement remarkably, resulting mobility ratio improvement. Among clay NPs, the combination of natural polymer and kaolinite results in increased viscosity at all temperatures. Considerable wettability alteration was also observed in the case of natural polymer and illite NPs. Illite in combination with natural polymer showed an ability in reducing IFT. Finally, the results of displacement experiments revealed that the combination of natural polymer and kaolinite could be the best option for EOR due to its substantial ability to improve the recovery factor.

Zwitterionic-nonionic compound surfactant system with low chromatographic separation effect for enhanced oil recovery

Ultra-low oil/water interfacial tension (IFT) is an important parameter for evaluating the enhanced oil recovery performance of surfactant flooding. It is difficult to achieve ultra-low interfacial tension with crude oil by a single surfactant, so compound system is often used. However, the chromatographic separation effect of each component in the compound system will severely affect the practical oil displacement performance. In this study, a novel compound oil displacement system was prepared by a zwitterionic surfactant (oleic amidopropyl betaine, OAB) and a nonionic surfactant (coconut oil diethanolamide, CDEA) at a mass ratio of 1:1. The capability of reducing IFT, emulsification, wettability reversal and oil film peeling performance of this system were evaluated. The results show that by promoting the dense arrangement of surfactants at the oil/water interface and realizing hydrophilic-lipophilic balance, the OAB-CDEA compound system can reduce the IFT to 10−4 mN/m. The system also exhibits excellent emulsification performance, and when placed at undisturbed state, the small and uniform emulsion droplets demulsify spontaneously and completely within 3 h. The compound system can regulate the wettability of rock surface from oleophilic to strongly hydrophilic, increasing the underwater oil contact angle from 24° to 157°. Based on the static oil film peeling tests, the oil film reduction rate can reach 88%. Using a 0.3% compound system for the core flooding tests, a recovery up to 75% can be attained, which is ∼30% higher than that of simulated formation water flooding. Meanwhile, the system exhibits low chromatographic separation effect, with chromatographic separation factor Foc close to 1. The OAB-CDEA compound system proposed in this work demonstrates excellent oil displacement performance as well as low chromatographic separation effect, exhibiting great potential in oilfield practical application.

A viscosity study of charcoal-based nanofluids towards enhanced oil recovery

Research into nanofluids for enhanced oil recovery (EOR) has been carried out for more than a decade. Metal oxide nanoparticles dispersed in water are usually applied and the nanofluids can recover 8–16 % more of the original oil in place after or comparing to water flooding, while the oil recovery capacity of carbon tube nanofluids can be even better. Higher viscosities of nanofluids than that of water are one of the key properties that contribute to their good performance in EOR. This work, for the first time, prepared nanofluids from two charcoal samples as well as an active carbon sample for their possible application for EOR. The relationship of nanofluid viscosities with pH values as well as nanoparticle concentrations of the nanofluids was studied for their viscous behaviour in different shear conditions. Their representative viscosity data measured at 100 rpm were examined for the values of the so-called Dispersion Factor (DF). The determined DF values for the charcoal-based nanofluids are close to those of metal oxide nanofluids that have much smaller nanoparticle sizes. The highly porous active carbon nanofluid showed strong viscosity enhancement that is comparable to the values reported for nanofluids of carbon nanotubes. Due to their significant viscosity enhancement and carbon sequestration feature, the charcoal-based nanofluids are promising to be used for EOR.

Novel Anionic-Nonionic Surfactant Based on Water-Solid Interfacial Wettability Control for Residual Oil Development.

Irreversible colloidal asphaltene adsorption layers are formed on formation rock surfaces due to long-term contact with crude oil, and large amounts of crude oil adhere to these oil-wet layers to form residual oil films. This oil film is difficult to peel off due to the strong oil-solid interface effect, which seriously restricts further improvement in oil recovery. In this paper, the novel anionic-nonionic surfactant sodium laurate ethanolamide sulfonate (HLDEA) exhibiting strong wetting control was synthesized by introducing sulfonic acid groups into the nonionic surfactant laurate diethanolamide (LDEA) molecule through the Williamson etherification reaction. The introduction of the sulfonic acid groups greatly improved the salt tolerance and the absolute value of the zeta potential of the sand particles. The experimental results showed that HLDEA altered the wettability of the rock surface from oleophilic to strongly hydrophilic, and the underwater contact angle increased substantially from 54.7 to 155.9°. In addition, compared with LDEA, HLDEA exhibited excellent salt tolerance and enhanced oil recovery performance (the oil recovery was improved by 19.24% at 2.6 × 104 mg/L salinity). Based on nanomechanical experimental results, HLDEA was efficiently adsorbed on the core surfaces and regulated microwetting. Moreover, HLDEA effectively reduced the adhesion force between the alkane chains and the core surface, which facilitated residual oil stripping and oil displacement. This new anionic-nonionic surfactant affording great oil-solid interface wetting control has practical significance for the efficient development of residual oil.

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.

Optimization of operational strategies for rich gas enhanced oil recovery based on a pilot test in the Bakken tight oil reservoir

Horizontal well drilling and multistage hydraulic fracturing have been demonstrated as effective approaches for stimulating oil production in the Bakken tight oil reservoir. However, after multiple years of production, primary oil recovery in the Bakken is generally less than 10% of the estimated original oil in place. Gas huff ‘n’ puff (HnP) has been tested in the Bakken Formation as an enhanced oil recovery (EOR) method; however, most field pilot test results showed no significant incremental oil production. One of the factors affecting HnP EOR performance is premature gas breakthrough, which is one of the most critical issues observed in the field because of the presence of interwell fractures. Consequently, injected gas rapidly reaches adjacent production wells without contacting reservoir rock and increasing oil recovery. Proper conformance control is therefore needed to avoid early gas breakthrough and improve EOR performance. In this study, a rich gas EOR pilot in the Bakken was carefully analyzed to collect the essential reservoir and operational data. A simulation model with 16 wells was then developed to reproduce the production history and predict the EOR performance with and without conformance control. EOR operational strategies, including single- and multiple-well HnP, with different gas injection constraints were investigated. The simulation results of single-well HnP without conformance control showed that a rich gas injection rate of at least 10 MMscfd was needed to yield meaningful incremental oil production. The strategy of conformance control via water injection could significantly improve oil production in the HnP well, but injecting an excessive amount of water also leads to water breakthrough and loss of oil production in the offset wells. By analyzing the production performance of the wells individually, the arrangement of wells was optimized for multiple-well HnP EOR. The multiwell results showed that rich gas EOR could improve oil production up to 7.4% by employing conformance control strategies. Furthermore, replacing rich gas with propane as the injection gas could result in 14% of incremental oil production.

Reservoir heterogeneity controls of CO2-EOR and storage potentials in residual oil zones: Insights from numerical simulations

Residual oil zones (ROZs) have large potential for CO2 enhanced oil recovery (EOR) and geologic storage. During CO2 injection, the migration of CO2 in ROZs controls the performance of both EOR and storage. However, it has not been clearly visualized and understood that how geological heterogeneity factors control the transport of CO2 in ROZs. In this study, the oil recovery performance and geologic storage potential during continuous CO2 injection in a representative ROZ are studied based on geostatistical modelling and high-fidelity three-phase flow simulation. We examined the influence of autocorrelation length of permeability, global heterogeneity (Dykstra–Parsons coefficient), and permeability anisotropy on cumulative oil recovery and CO2 retention fraction. Simulation results indicate that, as the permeability autocorrelation length increases, the cumulative oil recovery and CO2 storage efficiency decrease. This results from the accelerated migration of CO2 along high permeability zones (i.e., gas channeling). The increase in global heterogeneity and permeability anisotropies can lead to low oil recovery and poor CO2 sequestration performance, depending on the degree of CO2 channeling. The net utilization ratio of CO2 (CO2 retained/oil produced) unfavorably increases with both autocorrelation length and Dykstra–Parsons coefficient, but decreases with the increase in kv/kh. Such a decrease is attributed to enlarged swept volume induced by gravity override. The study provides important implications for field-scale CO2 EOR and storage applications in ROZs.

Stability and enhanced oil recovery performance of CO2 in water emulsion: Experimental and molecular dynamic simulation study

Enhanced oil recovery by CO2 flooding is conducive to energy and environmental development. However, the geological storage capacity and oil recovery of CO2 are relatively low due to its low viscosity, gravity segregation, and reservoir heterogeneity. CO2 in water (C/W) emulsion can reduce CO2 mobility and increase the volumetric efficiency of CO2. This paper investigated the stability and recovery performance of C/W emulsion. The results show that the C/W emulsion formed by AOT was more stable than the C/W emulsion formed by SDS. CO2 molecules were difficult to penetrate through AOT layers due to two hydrophobic chains in AOT molecules. Emulsion stability tests show that C/W emulsion was more stable with higher pressures and lower temperatures. The AOT hydrophobic chains were tightly packed at high pressure, thus increasing the thickness of the AOT layer, which can increase the stability of the C/W emulsion. Enhanced oil recovery by C/W emulsion at 8, 10, and 12 MPa was 23.72%, 34.88%, and 39.27%. The produced oil's density, viscosity, and asphaltenes content after C/W emulsion flooding were much lower than the original crude oil. Asphaltenes in residual oil were higher than in the original crude and produced oil. The micromodel test and MD simulation study indicate that CO2 could extract light components from the crude oil, including saturates and aromatics. As a result, the asphaltenes molecules would aggregate and precipitate. The light saturates molecules absorbed by the oil–water interface could form oil in water droplets and produce during the C/W emulsion flooding. The heavy components, including resins and asphaltenes, remained in the oil phase.

Interfacial and rheological investigation of enhanced oil recovery agents derived from Spirulina biomass

This study investigates interfacial and rheological properties of novel, Spirulina-based fluids developed for potential use in enhanced oil recovery (EOR) applications. The purpose of this investigation is to determine the driving mechanism(s) behind the EOR performance of these materials after a previous study concluded that the EOR fluids are a promising technology with up to 96% recovery of the original oil in place (OOIP). It was then hypothesized that the EOR mechanism arose from the interfacial energy effects and/or the rheological properties. In this study, Arthrospira platensis (Spirulina) biomass is modified by different denaturants (sodium hydroxide, citric acid, and urea) and tested for a wide range of interfacial and rheological properties. The interfacial properties include surface tension, interfacial tension with hydraulic oil, contact angle against silicon dioxide, and work of adhesion between the fluid and the silicon dioxide surface. The rheology focuses on determining fluid viscoelastic properties and flow behaviors. Additionally, this study compares and correlates the results amongst each other, which also includes pH, EOR performance, and denaturant concentration.The EOR performance of these fluids strongly correlates with the increased viscosity, reduced interfacial tension (IFT), and increased wettability in the EOR fluids. All of the investigated EOR solutions reduced the IFT. Most of the EOR solutions were found to be mostly shear-thinning with shear-thickening approximately in the 2,000–5,000 s−1 range. From the results, it is concluded that the performance of the different types of EOR fluids is based on different mechanisms. Sodium hydroxide-based fluids are driven by increased low-shear viscosity, reduced IFT, alkaline pH shift, and improved wettability. The citric acid-based fluids do not exhibit high viscosity values in the low shear range, which indicates that their EOR performance seems to be driven by reduced IFT, acidic pH shift, improved wettability, and increased fluid rigidity by the generation of crosslinks in the macromolecular structure. Urea-based fluids did not exhibit improved viscosity, which means that their modest EOR performance is likely driven by reduced IFT and improved wettability. While a shear-thickening rheology is often considered to be a mechanism for improving EOR, it is concluded that the shear-thickening effect is not a dominant mechanism for these fluids, especially since the highest performing EOR fluid (highest NaOH concentration) did not display shear thickening.

Application of surfactants in enhancing oil recovery from tight carbonates: Physicochemical properties and core flooding experiments

Surfactant formulations are optimized according to reservoir conditions to ensure their efficiency in enhanced oil recovery (EOR). This experimental study aimed to examine the EOR performance of a group of novel Alfoterra surfactants, which are based on alcohol propoxy sulfates. The performance of the Alfoterra surfactants (anionic) was compared to that of sodium dodecyl sulfate (SDS, anionic), dodecyltrimethylammonium bromide (DTAB, cationic), cetyltrimethylammonium bromide (CTAB, cationic) and t-octylphenoxypolyethoxyethanol (Triton X-100, nonionic). First, surfactant formulations were optimized based on their critical micelle concentration as well as their aqueous stability at 55 °C under different salinities. Next, the effects of the stable surfactant formulations on the interfacial tension (IFT) and rock wettability were examined. It was shown that the presence of the surfactants and the increase in salinity both caused a significant reduction in the oil-water IFT. Additionally, all surfactant formulations altered the wettability of carbonate rock from intermediate-to water-wet conditions. Next, tests of surfactant adsorption onto a carbonate-rock adsorbent were performed, showing that the anionic surfactants tend to adsorb more onto carbonates compared to other surfactants. Finally, core flooding tests involving medium-viscosity oil recovery from tight carbonate cores showed an EOR of 25.7–39.4% of original-oil-in-place above that achieved using regular waterflooding.

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

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

Investigating Enhanced Oil Recovery in Unconventional Reservoirs Based on Field Case Review, Laboratory, and Simulation Studies

Aimed at advancing gas injection enhanced oil recovery (EOR) technologies in unconventional reservoirs, this study comprised a series of activities to bridge the gap between the theoretical study and actual field applications. Twenty-four EOR pilot tests were collected from the major unconventional plays in North America to evaluate the performance of different EOR technologies. Fit-for-purpose experiments and simulations were performed to investigate the effects of injection rate and pressure on EOR performance, as well as to reveal the effectiveness of huff “n” puff (HnP) cycles in actual field operations. The selection of injection rate and pressure as key parameters for investigation was based on field observations and communications with oil and gas operators because these two parameters play critical roles in both facility design and overall cost for an EOR project. Results showed that miscible EOR with a high gas injection rate and pressure is required for field operations because the injected gas needs to penetrate and extract oil from the tight matrix. Experimental results indicated that there is a correlation between oil recovery and the logarithm of core volume for miscible EOR. Immiscible gas EOR could not yield a satisfactory EOR response in actual reservoirs because the injected gas tends to flow through fractures instead of penetrating the matrix to interact with oil. Results also showed that reaching minimum miscibility pressure (MMP) does not guarantee an optimum EOR operation in unconventional reservoirs. Pressure higher than MMP is preferred in field operations. When designed properly, up to a tenfold oil production rate boost is achievable in field applications within a short period. However, such a high-performance operation is only effective in the first several HnP cycles due to the limited gas penetration depth into the rock matrix.

Surface-functionalized cellulose nanocrystals (CNC) and synergisms with surfactant for enhanced oil recovery in low-permeability reservoirs

Nanocellulose, a natural polymeric nanomaterial, has attracted significant attention in enhanced oil recovery (EOR) applications due to its abundance, nanoscale, high oil–water interfacial adsorption efficiency. In this study, surface-functionalized cellulose nanocrystals (SF-CNCs) were prepared via hydrochloric acid hydrolysis and chemical modification, with adaptable nanosize and considerable dispersion stability in low-permeability reservoirs. The SF-CNCs were structurally characterized by FT-IR, Cryo-TEM, which have a diameter of 5–10 nm and a length of 100–200 nm. The SF-CNC dispersions possessed higher stability and stronger salt-tolerance than those of corresponding CNC dispersions, due to the strong hydrophilicity of the sulfonic acid group. It was synergistically used with a non-ionic surfactant (APG1214) to formulate a combined flooding system (0.1 wt% SF-CNC + 0.2 wt% APG1214). The combined flooding system exhibits strong emulsification stability, low oil–water interfacial tension of 0.03 mN/m, and the ability to alter the wettability for oil-wetting rocks. Furthermore, the combined system was able to provide an optimum EOR efficiency of 20.2% in low-permeability cores with 30.13 × 10−3 μm2. Notably, it can enlarge the sweep volume and increase the displacement efficiency simultaneously. Overall, the newly formulated nanocellulose/surfactant combined system exhibits a remarkable EOR performance in low-permeability reservoirs.

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.