Oil Recovery In Low Permeability Reservoirs Research Articles

Tailoring Water-Gas Ratios to Saturation Distribution for Improved Oil Recovery in Low-Permeability Reservoirs.

Water-gas alternation technology (WAG) is considered to be one of the methods that can effectively improve the effect of the CO2 flooding in heterogeneous reservoirs. The proportion of WAG and the timing of WAG adjustment are key factors affecting the oil displacement effect. This article analyzes the influence of adjusting the WAG ratio on the oil recovery effect of heterogeneous rock cores at different gas flooding stages based on gas flooding experiments. Second, the influence of WAG ratio changes on the recovery rate of displacement experiments under different saturation distributions was studied through numerical simulation. Finally, the oilfield model currently in production was used to optimize the WAG ratio adjustment of the reservoir recovery as a constraint condition. Moreover, the correlation between the fluid distribution of the reservoir and the timing of WAG adjustment was verified. The displacement experiment shows that adjusting the WAG ratio has a significant impact on the displacement effect of crude oil under the same heterogeneous conditions. After adjusting the WAG ratio from 1:2 to 2:1 at 0.5 HCPV and 1 HCPV, the final RF showed significant changes. There is an optimal timing for adjusting the WAG ratio under the same heterogeneity. If the WAG ratio is increased earlier, it will lead to a decrease in the CO2 injection volume and reduce the effectiveness of CO2 flooding. If the WAG ratio is increased later, it will lead to the formation of gas channeling channels and affect the effect of adjusting the WAG ratio on flooding.

Enhancing Oil Recovery in Low-Permeability Reservoirs Using a Low-Molecular Weight Amphiphilic Polymer.

Polymer flooding has achieved considerable success in medium-high permeability reservoirs. However, when it comes to low-permeability reservoirs, polymer flooding suffers from poor injectivity due to the large molecular size of the commonly used high-molecular-weight (high-MW) partially hydrolyzed polyacrylamides (HPAM). Herein, an amphiphilic polymer (LMWAP) with a low MW (3.9 × 106 g/mol) was synthesized by introducing an amphiphilic monomer (Allyl-OP-10) and a chain transfer agent into the polymerization reaction. Despite the low MW, LMWAP exhibited better thickening capability in brine than its counterparts HPAM-1800 (MW = 1.8 × 107 g/mol) and HPAM-800 (MW = 8 × 106 g/mol) due to the intermolecular hydrophobic association. LMWAP also exhibited more significant shear-thinning behavior and stronger elasticity than the two counterparts. Furthermore, LMWAP possesses favorable oil-water interfacial activity due to its amphiphilicity. The oil-water interfacial tension (IFT) could be reduced to 0.88 mN/m and oil-in-water (O/W) emulsions could be formed under the effect of LMWAP. In addition, the reversible hydrophobic association endows the molecular chains of LMWAP with dynamic association-disassociation transition ability. Therefore, despite the similar hydrodynamic sizes in brine, LMWAP exhibited favorable injectivity under low-permeability conditions, while the counterpart HPAM-1800 led to fatal plugging. Furthermore, LMWAP could enhance oil recovery up to 21.5%, while the counterpart HPAM-800 could only enhance oil recovery by up to 11.5%, which could be attributed to the favorable interfacial activity of LMWAP.

Front Movement and Sweeping Rules of CO2 Flooding under Different Oil Displacement Patterns

CO2 flooding is a pivotal technique for significantly enhancing oil recovery in low-permeability reservoirs. The movement and sweeping rules at the front of CO2 flooding play a critical role in oil recovery; yet, a comprehensive quantitative analysis remains an area in need of refinement. In this study, we developed 1-D and 2-D numerical simulation models to explore the sweeping behavior of miscible, immiscible, and partly miscible CO2 flooding patterns. The front position and movement rules of the three CO2 flooding patterns were determined. A novel approach to the contour area calculation method was introduced to quantitatively characterize the sweep coefficients, and the sweeping rules are discussed regarding the geological parameters, oil viscosity, and injection–production parameters. Furthermore, the Random Forest (RF) algorithm was employed to identify the controlling factor of the sweep coefficient, as determined through the use of out-of-bag (OOB) data permutation analysis. The results showed that the miscible front was located at the point of maximum CO2 content in the oil phase. The immiscible front occurred at the point of maximum interfacial tension near the production well. Remarkably, the immiscible front moved at a faster rate compared with the miscible front. Geological parameters, including porosity, permeability, and reservoir thickness, significantly impacted the gravity segregation effect, thereby influencing the CO2 sweep coefficient. Immiscible flooding exhibited the highest degree of gravity segregation, with a maximum gravity segregation degree (GSD) reaching 78.1. The permeability ratio was a crucial factor, with a lower limit of approximately 5.0 for reservoirs suitable for CO2 flooding. Injection–production parameters also played a pivotal role in terms of the sweep coefficient. Decreased well spacing and increased gas injection rates were found to enhance sweep coefficients by suppressing gravity segregation. Additionally, higher gas injection rates could improve the miscibility degree of partly miscible flooding from 0.69 to 1.0. Oil viscosity proved to be a significant factor influencing the sweep coefficients, with high seepage resistance due to increasing oil viscosity dominating the miscible and partly miscible flooding patterns. Conversely, gravity segregation primarily governed the sweep coefficient in immiscible flooding. In terms of controlling factors, the permeability ratio emerged as a paramount influence, with a factor importance value (FI) reaching 1.04. The findings of this study can help for a better understanding of sweeping rules of CO2 flooding and providing valuable insights for optimizing oil recovery strategies in the field applications of CO2 flooding.

Study on the main factors and mechanism of functional silica nanofluid spontaneous imbibition for enhanced oil recovery

Nanofluids have shown great potential as chemical additives for enhanced oil recovery in low-permeability reservoirs owing to their unique properties. However, their application in harsh reservoir conditions poses challenges due to the demanding stability requirements. In this work, the functional silica nanofluid capable of withstanding high salinity and elevated temperature was prepared by blending 0.1 wt% hydrophilic silica sol with the 0.1 wt% modifier lauramidopropyl hydroxy sulfobetaine. Multiple experiments of the nanofluid were conducted, encompassing characterization, interfacial tension (IFT) and contact angle measurements. The nanoparticles had an average size of approximately 17 nm, and the nanofluid exhibited excellent stability, interfacial activity and wettability alteration ability. Spontaneous imbibition tests demonstrated that the nanofluid achieved a remarkable recovery of 35.30 %, compared with only 5.53 % for simulated formation water. Subsequently, the relationship between spontaneous imbibition recovery and factors, such as temperature, salinity and core permeability, was investigated. The influence weight for each factor on the recovery is as follows: temperature (64.61 %) > core permeability (19.07 %) > salinity (16.32 %). Furthermore, a comprehensive description of the spontaneous imbibition mechanism of nanofluids was provided, incorporating insights from 1HNMR results. We expect that this study can offer valuable insights into nanofluid formulation, supporting the efficient development of low-permeability reservoirs and provide a theoretical basis for field applications.

The Difference in Damage to Low-Permeability Reservoirs by Different Injection Methods of CO2 Flooding

Low-permeability reservoirs have become an important field of oil and gas development in China. CO2 flooding technology is an effective technical means for tertiary oil recovery. Although the asphaltene in the system is deposited in the form of a solid after CO2 injection into the reservoir in contact with crude oil, which causes a certain blockage to the reservoir, the dissolution during the injection process improves the seepage capacity of the reservoir as a whole, and the damage degree of CO2 flooding to low-permeability reservoirs under different injection modes is different. In this paper, the damage degree of asphaltene precipitation to low-permeability reservoirs under different injection modes of CO2 flooding is quantitatively characterized. The mechanism experiment of organic scale plugging after continuous CO2 flooding and CO2–water alternate flooding, the wettability experiment of reservoirs, and the evaluation experiment of CO2–water solution on rock dissolution are carried out, and the variation characteristics of relative permeability curve parameters are evaluated. In this paper, the damage degree of asphaltene precipitation to low-permeability reservoirs under different injection modes of CO2 flooding is quantitatively characterized. The mechanism experiment of organic scale plugging after continuous CO2 flooding and CO2–water alternate flooding, the wettability experiment of reservoirs, and the evaluation experiment of CO2–water solution on rock dissolution are carried out. The variation characteristics of relative permeability curve parameters are evaluated. The results show that the organic scale produced by CO2 flooding will block the pore throat of the rock, but, on the whole, the dissolution caused by the reaction of CO2 and chlorite is stronger, which makes the recovery rate of low-permeability reservoirs effectively improved. The organic scale blockage caused by CO2–water alternating flooding is weaker than that caused by continuous CO2 flooding. The dissolution effect is better and the permeability is higher. It can achieve a better oil displacement effect in pores with a pore size greater than 0.2 μm. On the whole, it can increase the core pore space and seepage channel, so that the recovery rate of low-permeability reservoirs can be effectively improved. This study has important theoretical and practical significance for improving oil recovery in low-permeability reservoirs.

Fractal model of spontaneous imbibition in low-permeability reservoirs coupled with heterogeneity of pore seepage channels and threshold pressure

Spontaneous imbibition (SI) is an important mechanism for enhancing oil recovery in low-permeability reservoirs. Due to the strong heterogeneity, and the non-Darcy flow, the construction of SI model for low-permeability reservoirs is extremely challenging. Commonly, traditional SI models based on single or averaged capillary tortuosity ignore the influence of heterogeneity of pore seepage channels and the threshold pressure (TP) on imbibition. Therefore, in this work, based on capillary model and fractal theory, a mathematical model of characterizing SI considering heterogeneity of pore seepage channels is established. On this basis, the threshold pressure was introduced to determine the pore radius at which the wetted phase can displace oil. The proposed new SI model was verified by imbibition experimental data. The study shows that for weakly heterogeneous cores with permeability of 0–1 mD, the traditional SI model can characterize the imbibition process relatively accurately, and the new imbibition model can increase the coefficient of determination by 1.05 times. However, traditional model has serious deviations in predicting the imbibition recovery for cores with permeability of 10–50 mD. The new SI model coupling with heterogeneity of pore seepage channels and threshold pressure effectively solves this problem, and the determination coefficient is increased from 0.344 to 0.922, which is increased by 2.68 times. For low-permeability reservoirs, the production of the oil in transitional pores (0.01–0.1 μm) and mesopores (0.1–1 μm) significantly affects the imbibition recovery, as the research shows that when the heterogeneity of pore seepage channels is ignored, the oil recovery in transitional pores and mesopores decreases by 7.54% and 4.26%, respectively. Sensitivity analysis shows that increasing interfacial tension, decreasing contact angle, oil–water viscosity ratio and threshold pressure will increase imbibition recovery. In addition, there are critical values for the influence of these factors on the imbibition recovery, which provides theoretical support for surfactant optimization.

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.

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.

New Technique for Enhancing Residual Oil Recovery from Low-Permeability Reservoirs: The Cooperation of Petroleum Hydrocarbon-Degrading Bacteria and SiO2 Nanoparticles.

Residual crude oil production from low-permeability reservoirs has become a huge challenge because conventional recovery techniques are inefficient. Nanofluids as a new type of oil-displacement agent have become a hot topic in recent years to enhance oil recovery (EOR) in reservoirs. However, the imperfection of agglomeration, dissolution, and instability of nanofluids in reservoir environments limit their ability to drive oil. Here, a novel "microbial-nanofluid" composed of petroleum hydrocarbon-degrading bacteria (PHDB, namely Bacillus cereus) and SiO2 nanoparticles was proposed as a potential new technology for enhancing residual oil recovery. The micromodel displacement test results showed that the optimum composite concentration of "microbial-nanofluids" were PHDB (7.0%, v/v) and SiO2 nanoparticles (100 mg/L), and the residual oil recovery was increased by 30.1% compared with waterflooding (68.8%). Moreover, the morphological characteristics of residual oil mobilization after "microbial-nanofluid" flooding were mainly small and dispersed oil droplets in the excessive areas, and the dead-end areas were almost clean with mobilization. Furthermore, the cooperation mechanism of four kinds of "microbial-nanofluids" to enhance the residual oil recovery in low-permeability reservoirs was preliminarily clarified, namely the co-emulsification of oil, working together to unclog oil clog, microbial-nanofluid self-assembly, and structural disjoining pressure. This study demonstrated that PHDB-SiO2 nanoparticle composite flooding technology provided a significant potential for the EOR from low-permeability reservoirs.

Construction and Performance Evaluation of Dual-Metabolite Oil-Producing Engineering Bacteria Suitable for Low-Permeability Reservoir

Abstract Microbial oil recovery (MEOR) technology has a wide application prospect in the field of enhanced oil recovery in low-permeability reservoirs, and genetic engineering plays an important role. At present, oil-production engineering bacteria constructed by genetic engineering are mainly used to obtain high metabolites and strong environmental adaptability; there are few reports on genetically engineered bacteria with different functional metabolites. However, the bacteria which could efficiently produce one metabolite have a poor ability to produce other metabolites. Therefore, in order to reduce the cost of nutrients and improve the effect of microbial oil recovery, dual-metabolite bacteria have been constructed for low-permeability reservoir. In this paper, four rhamnolipid expression plasmids are extracted from E. coli-produced biosurfactant. Then, the rhamnolipid expression plasmids are transferred into the bacteria-produced biopolymer by electrotransformation, and the metabolite performance of the constructed bacteria is evaluated. Finally, the profile control and displacement performance of the constructed bacteria are studied through low-permeability core experiments. The experimental results show that three bacteria, WS1, WS2, and WS3, are successfully constructed that have preferable ability, among which the bacteria WS2 has the best capacity for producing biopolymer and biosurfactant at the same time. After culturing 96 h, the viscosity of the bacteria WS2 fermentation broth could increase to 42.1 mPa·s, and the surface tension and interfacial tension of the fermentation broth could decrease to 24.3 mN/m and 0.035 mN/m, respectively. This time-varying biological viscosity ensures that the microbial system can enter the low-permeability reservoir at a low injection pressure, and the oil recovery of the low-permeability core could be increased by 10.18% after injecting 0.5 PV WS2 microbial system. The findings of this study can help for better understanding of gene construction and technical support for further popularization and application of MEOR in low-permeability reservoirs.

A novel amphiphilic Janus nano-silica for enhanced oil recovery in low-permeability reservoirs: An experimental study

The hydrophilic nano-silica (HNS) has become a research hotspot in multiple fields due to its cost-effectiveness and environmental protection. However, due to the lack of the amphiphilic structure, the HNS is unable to reduce interfacial tension (IFT), which is adverse to the recovery of residual oil from reservoirs. Therefore, it is of great significance to prepare amphiphilic Janus nano-silica similar to surfactant for enhanced oil recovery (EOR). In this present work, a sulfonic/alkane composite amphiphilic Janus nano-silica (SAJNS) was fabricated through the Pickering emulsion template approach under specific conditions, and its surface structure was confirmed through related characterization techniques. Then, 500 ppm of the SAJNS was dispersed in different based fluids to prepare corresponding nanofluids. The prepared nanofluids could remain stable at 50 °C during storage for one week. Benefiting from the amphiphilic characteristic, the SAJNS migrated from the aqueous phase to the oil-water interface and thus reduced the IFT, which made the residual oil remobilize inside the pore throats. The measurement result of the contact angle illustrated that the oil-wet thin slice treated with the nanofluid became water wet. SEM and EDS techniques indicated that the adsorption of the SAJNS on the surface of the thin slice was responsible for the wetting alteration. Besides, almost all the crude oil adsorbed on the glass slide face was stripped after immersion in the nanofluid. The core flooding experiment demonstrated that the injected nanofluid helped to recover residual oil and decrease injection pressure. The NMR results presented that most recovered residual oil was from the micropores.

Effect of in-situ emulsification of surfactant on the enhanced oil recovery in low-permeability reservoirs

Surfactant flooding technology has become an important treatment for the enhance oil recovery (EOR) in low-permeability reservoirs, and which behavior of surfactant is more important for EOR, lowering interfacial tension (IFT) or in-situ emulsification, is still debatable. In this work, to ascertain the dominating behavior of surfactant, a series of comparative experiments were performed to observe their dynamic flooding performances in artificial cores over a permeability range between 5 mD and 50 mD. Besides, a 2D heterogeneous model was used to explore the effect of micro heterogeneity on surfactant flooding. At last, the adaptable limits, including heterogeneous degree and injective time, were further discussed. The results show, the overall oil recovery increases with permeability, while their flooding dynamics also changes with permeability. The results show, in-situ emulsification of surfactant plays the key role in oil recovery compared with IFT reduction, especially with the cores’ permeability decreasing. On the one hand, the strong emulsifying capability of surfactant is advantageous in dispersing the residual oil to reduce oil saturation. On the other hand, the formation of amounts of emulsion droplets is useful to block the pore and further contributes to establish pressure variation and delaying water-cut raising. Meanwhile, strong emulsifying capacity of surfactant is positive to improve the swept efficiency in micro heterogeneous distributions and avoid the formation of micro water channel. Lastly, the adaptable conditions tests indicate the extremely strong heterogeneity and low crude oil saturation are the crucial factor to affect the EOR performances owing to the ease of in-situ emulsification formation. Therefore, this finding of this study can help for better understanding of contribution of in-situ emulsification of surfactant for EOR and its limitations in low-permeability reservoirs, which could be a candidate with great potentials for field application and economic returns.

Simulation of imbibition in porous media with a tree-shaped fracture following the level-set method

Imbibition is an important mechanism for enhancing oil recovery in low-permeability reservoirs, such as shale and tight sandstone, and a tree-shaped network has been successfully used to characterize fracturing fracture. Therefore, understanding the imbibition mechanism in porous media with a tree-shaped fracture (TFPM) is important for developing low-permeability reservoirs. In this study, a simulation model for imbibition in TFPM was established based on the level-set method, and the model was verified by comparing it with an analytical solution. The influences of the fracture width, bifurcation angle, tortuosity, and water flow rate on imbibition in TFPM were then discussed. Based on the results, the following points have been established: (1) During the early stage, the imbibition in TFPM included countercurrent and a combined imbibition, and only countercurrent imbibition occurred during the later stage. (2) At a constant fracture width ratio, increasing the primary fracture width could reduce the residual oil in the TFPM, thereby improving the oil recovery factor. (3) At a fracture bifurcation angle ranging from 0° to 45°, the oil recovery factor increased as the bifurcation angle increased. (4) At a fracture tortuosity of 1.0 to 1.24, changes in tortuosity had little effect on the oil recovery factor during the early stage of imbibition, while it significantly affected the distribution of the residual oil. (5) At a water flow rate of 5 mm/s, the simulated oil recovery factor in the TFPM was highest. This investigation can provide a reference for the development of low-permeability reservoirs.

Key geological factors controlling oil displacement efficiency of CO2 injection in low-permeability reservoirs

Carbon dioxide (CO2) flooding is an effective method to enhance oil recovery in low-permeability reservoirs. Studying key geological factors controlling oil displacement efficiency is of great significance to the CO2 injection scheme design in low-permeability reservoirs. Focusing on low-permeable H reservoir in Songliao Basin, China, this paper describes the contact and connection of sand bodies, natural fractures and high-permeability zones with core samples, log data and experiment firstly. After that, the impact of interaction of sand body connection, natural fracture and high-permeability zone on oil displacement efficiency is determined by using geological and dynamic data in CO2 injection area. Results indicate that the connection of single sand bodies between injectors and producters wells primarily controls CO2 flooding in low-permeability reservoirs. Furthermore, coupling of sand body connection, natural fractures and high-permeability zones is the key geological factor governing oil displacement efficiency of CO2 injection in low-permeability reservoirs, where well or generally-connected sand bodies can improve the efficiency significantly. Meanwhile, the dominant seepage channels in other directions have no influence on producers, which is beneficial to improve CO2 flooding efficiency.

Microbubbles generation by an orifice spraying method in a water-gas dispersion flooding system for enhanced oil recovery

In China, many oilfields with low permeability and heterogeneity have entered the secondary oil recovery stage, in which more oil displacement agents for expanding sweep volume has become a key technology. A water-gas dispersion flooding system is reasonably proposed to change the seepage resistance and adjust the mobility ratio. In this EOR technique, the generation of micron-sized bubbles in the low-permeability reservoir is of considerable interest. In this study, a visual device by using an orifice spraying method was designed to simulate reservoir conditions with high temperature and high pressure, and efficiently to produce more microbubbles. Based on the orifice spraying method, the morphological characteristics of microbubbles generated by different orifice plate materials were compared, which provided the choice of the microbubbles generation by the orifice spraying method for laboratory experiments. Besides, the influence of different factors on the quantity and size of microbubbles produced by a single orifice plate was presented in detail. The experimental results showed that the diameter of the microbubbles generated by the orifice spraying method under a hypothetic reservoir condition was about 10–100 μm. These visual experimental devices were practically designed to meet the demand of the micron-level pores and throats to enhance oil recovery in low-permeability reservoirs. This investigation of microbubbles generation provided the basic research means for further preparation of a water-gas dispersion flooding system.

Functions of capillary pressure and dissolution in the CO2-flooding process in low-permeability reservoirs

CO2 flooding has become one of most effective methods to improve oil recovery in low-permeability reservoirs. Thus, influencing factors have been specifically analyzed for their impact on oil displacement. Factors that are difficult to observe, such as capillary pressure and CO2 dissolution, have often been neglected in specific analysis. To do so, this paper combined laboratory experimentation with numerical simulation analysis to understand the specific functions of capillary pressure and CO2 dissolution in the CO2-flooding process in low-permeability reservoirs. Based on laboratory experiments with long cores applying different CO2-flooding methods, the authors established a one-dimensional numerical simulation model for CO2 flooding. After that, the model was simulated to analyze the effects of capillary pressure and CO2 dissolution for different CO2-flooding processes. The results show that the function of capillary pressure in different CO2-flooding modes is not consistent in low-permeability reservoirs; furthermore, capillary pressure is a driving force in the process of flooding and is a resistance force in the CO2-flooding process after pressure recovery. When considering CO2 dissolution in different flooding modes, its function was shown to be inconsistent in low-permeability reservoirs compared with CO2 flooding without considering CO2 dissolution; oil recovery is reduced in the CO2-flooding process, but oil recovery increases in the CO2-flooding process after pressure recovery. Therefore, in order to promote the rational and effective development of low-permeability reservoirs, it is necessary to understand the functions of capillary pressure and CO2 dissolution clearly in the process of CO2 flooding.

Enhancing oil recovery from low-permeability reservoirs with a self-adaptive polymer: A proof-of-concept study

Considerable success has been achieved in enhanced oil recovery by polymer flooding from high- to medium-permeability reservoirs; however, the poor injectivity and ease of mechanical degradation of the commonly used high-molecular-weight (high-MW) partially hydrolyzed polyacrylamides (HPAM) impede their use in low-permeability reservoirs. To alleviate these issues, we proposed the use of the self-adaptive polymer (SAP). SAP with a relatively low MW (8.7 × 106 g mol−1), a rigid unit, and hydrophobic pendant group was prepared and compared with its counterparts HPAM-1 (8.2 × 106 g mol−1) and HPAM-2 (24.9 × 106 g mol−1). It was found that while the molecular size of SAP is similar to that of HPAM-1, its thickening capability is stronger under identical conditions, and both of them can be smoothly injected into the 60-mDarcy cores. By contrast, HPAM-2 causes fatal plugging in this scenario. The favorable injectivity of SAP solution stems from its reversible viscosity change in response to shear forces without any deterioration, which is achieved by the association-disassociation transition of molecular chains. In the elongational field, both SAP and HPAM-1 do not degrade mechanically, as opposed to the case of HPAM-2. More significantly, SAP can improve oil recovery up to 18.7%, which is around three times higher than that of HPAM-1. This self-adaptive concept may open a new pathway for the molecular design of polymers used for enhancing oil recovery in low-permeability reservoirs.

Optimized Cyclic Water Injection Strategy for Oil Recovery in Low-Permeability Reservoirs

With the worldwide decline in conventional oil production, tremendous unconventional resources, such as low-permeability reservoirs, are becoming increasingly important. Cyclic water injection (CWI) as an oil recovery method has attracted increasing attention in the present environment of low oil prices. However, the optimal CWI strategy is difficult to determine for a mature oilfield due to the involvement of multiple wells with multiple operational parameters. Thus, our main focus in this paper is to present a novel and systematic approach to optimize CWI strategies by studying a typical low-permeability, namely, reservoir G21. To this end, a comprehensive method that combines the advantages of streamline simulation and fuzzy comprehensive evaluation (FCE) was proposed to identify water channeling in the reservoir. Second, the reliability of the method was verified using tracer tests. Finally, a new hybrid optimization algorithm, the simulated annealing-genetic algorithm (SAGA), coupled with a reservoir simulator was developed to determine an optimal CWI strategy for the low-permeability reservoir. The results show that the CWI technique is viable as a primary means in the present environment of low oil prices to improve the waterflood performance in low-permeability reservoirs. The oil recovery of the most efficient strategy increases by 6.8% compared to conventional waterflooding. The asymmetric CWI scheme is more efficient than the symmetric CWI scheme for the low-permeability reservoir.

Microbial Mineralization of Montmorillonite in Low-Permeability Oil Reservoirs for Microbial Enhanced Oil Recovery.

Microbial mineralization (corrosion, decomposition, and weathering) has been investigated for its role in the extraction and recovery of metals from ores. Here we report our application of biomineralization for the microbial enhanced oil recovery in low-permeability oil reservoirs. It aimed to reveal the etching mechanism of the four Fe(III)-reducing microbial strains under anaerobic growth conditions on Ca-montmorillonite. The mineralogical characterization of Ca-montmorillonite was performed by Fourier transform infrared spectroscopy, X-ray powder diffraction, scanning electron microscopy, and energy-dispersive spectrometry. Results showed that the microbial strains could efficiently reduce Fe(III) at an optimal rate of 71%, alter the crystal lattice structure of the lamella to promote interlayer cation exchange, and efficiently inhibit Ca-montmorillonite swelling at a rate of 48.9%.IMPORTANCE Microbial mineralization is ubiquitous in the natural environment. Microbes in low-permeability reservoirs are able to facilitate alteration of the structure and phase of the Fe-poor minerals by reducing Fe(III) and inhibiting clay swelling, which is still poorly studied. This study aimed to reveal the interaction mechanism between Fe(III)-reducing bacterial strains and Ca-montmorillonite under anaerobic conditions and to investigate the extent and rates of Fe(III) reduction and phase changes with their activities. Application of Fe(III)-reducing bacteria will provide a new way to inhibit clay swelling, to elevate reservoir permeability, and to reduce pore throat resistance after water flooding for enhanced oil recovery in low-permeability reservoirs.

Effectiveness of oil displacement by sequential low-salinity waterflooding in low-permeability fractured and non-fractured chalky limestone cores

Low-salinity waterflooding has been recognized as a method of enhancing oil recovery in low-permeability reservoirs. This method is relatively inexpensive and can be easily implemented in the field. Various mechanisms of low-salinity flooding have been proposed including interfacial tension reduction, wettability alteration (cation exchange), change in pH (increase), emulsion formation, and clay migration. Hydraulic fracturing has been known as a technique of stimulating hydrocarbon flow from low-permeability matrix into wellbores by creating high-conductivity fractures. The objective of this study is to evaluate the effectiveness of sequential low-salinity brine flooding process to enhance oil recovery in low-permeability fractured and non-fractured chalky limestone core samples. The low-salinity waterflooding tests were conducted with synthetic brines of five different salinity concentrations, namely, 157,662, 72,927, 62,522, 6252, and 1250 ppm. The properties of these brines have been thoroughly investigated in the laboratory. The crude oil and chalky limestone core samples, permeability range between 0.01 and 1.2 millidarcy, were gathered from a selected oil field in United Arab Emirates. When used as an opening move in a three-stage sequential brine flooding (SW/10→SW/50→SW 6xSO4− 2), sea water diluted ten times at 6252 ppm (SW/10) has been found to yield the highest oil recovery in fractured and non-fractured tests at the prevailing reservoir conditions, of 82.64 and 76% of OOIP, respectively. In all sequential brine flooding scenarios tested, sea water with sulfate concentration spiked six times (SW 6 × SO4− 2) only slightly increased oil recovery. The highest observed incremental recovery with sulfate spiking was 2.083% of OOIP. The effectiveness of oil displacement by sequential brine flooding has been attributed to mineral dissolution and fines migration which resulted in a favorable wettability alteration. This postulation of flow mechanism is confirmed by introducing a “flow resistance index” concept and measurements of key properties of the injected and effluent brines of each stage of the attempted sequential brine flooding scenarios. Results of this study could be consulted when selecting most efficient EOR method to develop tight carbonate oil reservoirs in the UAE and worldwide.