Low Permeability Fractured Reservoir Research Articles

Experimental Investigation of CO2 Huff-and-Puff Enhanced Oil Recovery in Fractured Low-Permeability Reservoirs: Core-Scale to Pore-Scale

CO2 huff-n-puff is regarded as an effective method to improve the recovery of low permeability and tight oil reservoirs. To understand the impact of CO2 huff-n-puff on crude oil mobilization in tight reservoirs with different fracture scales, this study conducted CO2 huff-n-puff nuclear magnetic resonance (NMR) and microscopic visualization experiments, focusing on how varying fracture apertures and densities affect the efficiency of the CO2 huff-n-puff. The results show that in scenarios with a single fracture, larger fracture apertures significantly boost oil mobilization within the fracture and the surrounding matrix. For instance, increasing the aperture from 20 μm to 70 μm improved the recovery factor by 9.20%. In environments with multiple fractures, greater fracture density enhances reservoir connectivity, and increases the CO2 sweep area, and the complex fracture model shows a 4.26% increase in matrix utilization compared to the simple fracture model. Notably, the improvement in recovery due to multi-scale fractures is most significant during the first two huff-and-puff cycles, with diminishing returns in subsequent cycles. Overall, increasing both fracture size and density effectively enhances crude oil mobilization in tight reservoirs. These findings provide valuable insights into improving the recovery efficiency of CO2 huff-and-puff techniques in tight oil reservoirs.

Experimental study on CO2 flooding within a fractured low-permeability reservoir: Impact of high injection rate

The rapid decay of reservoir energy in the late development of fractured low-permeability reservoir leads to poor development benefit. Injecting CO2 into such reservoir at high pressure and rate can rapidly replenish reservoir energy and fully utilize the advantages of CO2 flooding, which is an efficient approach for CCUS-EOR. Previous laboratory studies have mainly been conducted under conventional low injection rate, with little discussion on the impact of high injection rate (above 20 times the conventional low injection rate) on CO2 flooding, especially regarding the limited reports on the effect of high injection rate on CO2 flooding within a fractured low-permeability reservoir. In this paper, microscopic visualization and fractured-core experiments of CO2 flooding at different injection rates were conducted. The variations in microscopic displacement front and sweep characteristics under different injection rates were clarified. The influence of CO2 injection rate on the macroscopic and pore scale oil production characteristics in fractured low-permeability cores under different injection modes were analyzed. The results indicate that injection rate significantly influences the microscopic displacement characteristics. The final sweep coefficient at 10 μL/min was 25.07 %, and the pre-breakthrough sweep coefficient accounted for approximately 90 %. While for 200 μL/min, the final sweep coefficient was 34.83 %, and the post-breakthrough sweep coefficient accounted for above 50 %. During CO2 flooding in fractured low-permeability core, the oil production before CO2 channeling dominates the final oil recovery. Compared to 0.1 mL·min−1, oil recovery increases by above 20 % at a CO2 injection rate of 4 mL·min−1 at 6 PV. The high-pressure gradient formed by high injection rate enhances CO2 diffusion, promoting the oil mobilization in near-fracture and deep matrix. And it results to a decrease in the minimum pore scale of oil mobilization. Soaking enhances the interaction between CO2 and oil as well as the fluid exchange between fracture and matrix. It further reduces the minimum pore scale of oil mobilization, and the enhancing effect of soaking gradually strengthens with increasing injection rate. The results can provide theoretical reference for application of CO2 flooding within a fractured low-permeability reservoir.

Improvement and effectiveness analysis of dynamic/static imbibition experiments.

In low-permeability fractured reservoirs, there is a generalized fluid displacement between the replacement fluid in the fracture and the matrix crude oil. This imbibition behavior plays a crucial role in the development of this type of reservoir. The experimental devices for studying static imbibition behavior are generally susceptible to air pollution on the surface of the test core and a long testing period; the experimental devices for studying dynamic imbibition behavior are generally unable to eliminate the driving action. A dual-purpose experimental setup and an experimental method for dynamic or static imbibition that can avoid the above defects were designed. A method of fracture fluid flow rate calculation and motor speed conversion is proposed, and the method is used to assist in setting the parameters of dynamic imbibition experiments. The device was applied to compare the experimental effects with the static imbibition bottle and the dynamic replacement imbibition, respectively, and the effect of fracture width on the dynamic imbibition of repellent oil was investigated. The results show that: the static imbibition recovery rate of the dynamic/static imbibition experimental device is 1.55 percentage points higher than that of the imbibition bottle; the dynamic imbibition recovery rate is 3-6 percentage points lower than that of the driving dynamic imbibition method, and it can reflect the influence of a single flow rate condition on the imbibition; imbibition in low-permeability fractured reservoirs is more likely to take place in the fracture in the interval of 50-100 μm in the width.

The Formation Mechanism of Residual Oil and Methods of Enhanced Oil Recovery in a Fractured Low-Permeability Metamorphic Rock Reservoir in Bohai Bay

The oil reservoirs of the metamorphic rocks in Bohai Bay have geological characteristics such as low matrix porosity and permeability, developed natural microfractures, which result in the injection water rapidly advancing along fractures, a fast increase in the water content, and difficulties in extracting the remaining oil. In order to reveal water channeling and the residual oil formation mechanisms in fractured low-permeability reservoirs and solve the water channeling problem, we first analyzed the reservoir development status, then studied the formation mechanism of residual oil using a microfluidic chip device, and formed a method of hierarchical control to effectively control the water channeling problem of fractured reservoirs and maximize the displacement of residual oil. The results show that (1) Due to the low permeability of the reservoir matrix, a large amount of injected water flows along the fracture channel, which leads to the long-term high water cut of some oil wells and the retention of a large amount of crude oil in the matrix. (2) The results of microfluidic experiments show that the distribution of residual oil after water flooding mainly includes five types: blind end of the pore throat, columnar, cluster, flake and film, and residual oil. Among them, sheet-like and clustered residual oil are dominant, accounting for 75~85% and 10~13%, respectively. (3) Based on the characteristics of fracture development in buried-hill reservoirs, a hierarchical control technology of “gel particle + liquid crosslinked gel system” is established. The field application effect predicted that the input–output ratio was 1:3. This study provides a reference for the comprehensive treatment of water channeling in the same type of offshore fractured low-permeability metamorphic rock reservoirs.

Host-Guest recognition strengthened supramolecular preformed particle gel for conformance control in low-permeability fractured reservoirs

The conventional preformed particle gels (PPG) have problems of irreversibly shear-breakage after shearing actions during the application for conformance control in low-permeability fractured reservoirs. Herein, a novel host–guest recognition strengthened supramolecular PPG (S-PPG) was synthesized with synergistically non-covalent and covalent crosslinking structures, using host (allyl β-CD) and guest (cetyldimethylallyl ammonium chloride) monomers. Firstly, the chemical structures and micro-morphologies of S-PPG were systematically characterized by FTIR, Cryo-SEM, EDS and AFM methods. Then, the dispersion and thermal stability, swelling properties and rheological properties, including viscoelasticity, creep-recovery and shear self-healing abilities, of S-PPG were investigated, respectively. Finally, the low-permeability cores with fractures were used to identify the injectivity and plugging properties of S-PPG and conventional PPG. The results showed that the S-PPG exhibited strong crosslinking network, high dispersion and thermal stability. In addition, the S-PPG also displayed better swelling, viscoelasticity, creep-recovery and shear self-healing ability after equilibrated swelling process compared to those of conventional PPG. Finally, the S-PPG exhibited considerable compatibility with low-permeability cores with fracture width of 0.05 mm, and produced higher plugging rate (93.53 %) than conventional PPG (86.35 %). Therefore, the newly formulated supramolecular preformed particle gel (S-PPG) containing host–guest recognition can provide a new approach for solving the problems of irreversibly shear-breakage and improving the conformance control performance of PPG in low-permeability fractured reservoirs.

Application of CO2-Soluble Polymer-Based Blowing Agent to Improve Supercritical CO2 Replacement in Low-Permeability Fractured Reservoirs.

Since reservoirs with permeability less than 10 mD are characterized by high injection difficulty, high-pressure drop loss, and low pore throat mobilization during the water drive process, CO2 is often used for development in actual production to reduce the injection difficulty and carbon emission simultaneously. However, microfractures are usually developed in low-permeability reservoirs, which further reduces the injection difficulty of the driving medium. At the same time, this makes the injected gas flow very fast, while the gas utilization rate is low, resulting in a low degree of recovery. This paper conducted a series of studies on the displacement effect of CO2-soluble foaming systems in low-permeability fractured reservoirs (the permeability of the core matrix is about 0.25 mD). For the two CO2-soluble blowing agents CG-1 and CG-2, the effects of the CO2 phase state, water content, and oil content on static foaming performance were first investigated; then, a more effective blowing agent was preferred for the replacement experiments according to the foaming results; and finally, the effects of the blowing agents on sealing and improving the recovery degree of a fully open fractured core were investigated at different injection rates and concentrations, and the injection parameters were optimized. The results show that CG-1 still has good foaming performance under low water volume and various oil contents and can be used in subsequent fractured core replacement experiments. After selecting the injection rate and concentration, the blowing agent can be used in subsequent fractured cores under injection conditions of 0.6 mL/min and 2.80%. In injection conditions, the foaming agent can achieve an 83.7% blocking rate and improve the extraction degree by 12.02%. The research content of this paper can provide data support for the application effect of a CO2-soluble blowing agent in a fractured core.

A dual-porosity flow-net model for simulating water-flooding in low-permeability fractured reservoirs

The physics-based data-driven flow-network models with high computational efficiency have received great attention as the promising surrogate models for reservoir numerical simulation. However, the existing flow-network models developed for water-flooding reservoirs fail to consider different seepage characteristics of matrix and fractures and cannot be straightly applied to simulate the water-flooding process in low-permeability fractured reservoirs. In this study, we combine the flow-network model with the dual-porosity model to propose a new physics-based data-driven surrogate model, namely the Dual-Porosity Flow-Network Model (Flow-Net-DP), which can consider the non-Darcy flow in tight matrix and the stress-sensitive effects and preferential flow characteristic in fractures. Specifically, we refer to the dual-porosity model and use two channels to represent the connections between wells: one indicates the fracture system, the other represents the matrix system, and the fluid exchange between these two systems is considered by using a transfer function. Besides, each channel is discretized into one-dimensional grids, and a fully implicit scheme with Newton iteration is used to calculate pressure and saturation. Moreover, we establish an automated history matching method by using the Ensemble Smoother with Multiple Data Assimilation (ESMDA) algorithm to calibrate model parameters of Flow-Net-DP, and develop a production optimization method by using the Differential Evolution (DE) algorithm. Finally, the numerical simulation, history matching, and production optimization are conducted on different numerical examples to validate the capability of Flow-Net-DP. The results indicate that the Flow-Net-DP can provide a better description of water flooding process in low-permeability fractured reservoirs compared with the existing flow-network model, especially the rapid water breakthrough caused by the preferential flow characteristic in fractures. Furthermore, both history matching and production optimization based on the Flow-Net-DP yield satisfactory outcomes. For instance, when the optimization results are similar to the full-order simulation model, the optimization speed of Flow-Net-DP is increased by more than five times.

Gas channeling control with CO2-responsive gel system in fractured low-permeability reservoirs: Enhancing oil recovery during CO2 flooding

During the CO2 flooding process in fractured low-permeability oil reservoirs, the injected CO2 is prone to channeling along fractures due to severe reservoir heterogeneity, resulting in poor development effect. The CO2-responsive gel system shows dual advantages in achieving CO2 capture and plugging gas channeling to enhance oil recovery. This paper constructed a system with good CO2 sensitivity based on long-chain alkyl amide propyl dimethyl tertiary amine first. Subsequently, the properties of the system before and after the response were evaluated through rheological test, and its microstructure was characterized by Cryo-TEM. The system exhibited good CO2 responsiveness, transitioning from low-viscosity solution system to high-viscosity CO2-responsive gel system upon contact with CO2, with its viscosity increasing by nearly five orders of magnitude. The CO2-responsive gel demonstrated excellent shear resistance, viscoelasticity and shear self-repairing ability. The change of microstructure further verified the mechanism of molecules self-assembly in the system under the action of CO2. Then, a series of core physical simulation experiments were carried out to comprehensively evaluate the effects of different factors on the injection capacity, plugging characteristics, dynamic filtration damage performance and EOR effect of CO2-responsive gel. The gel maintained injectability while achieving an exceptional deep plugging effect, and the plugging rate reached 98.77%. It showed good characteristics of low filtration and permeability damage in low permeability reservoirs, effectively ensuring the fracture plugging effect. After the fracture was plugged by gel, the sweep range of CO2 to the matrix significantly expanded, and the gas flooding recovery increased by 18.19–21.7%. Finally, the matrix-fracture dual-media chip model was used to conduct microfluidic experiment, the oil displacement characteristics in different displacement stages were visually clarified, and the synergistic plugging and oil displacement mechanism between the CO2-responsive gel and CO2 was summarized. The research results can provide important insights for the green and efficient application of CO2-responsive gel in fractured low-permeability reservoirs.

Gelation and Plugging Performance of Low-Concentration Partially Hydrolyzed Polyacrylamide/Polyethyleneimine System at Moderate Temperature and in Fractured Low-Permeability Reservoir.

HPAM/PEI gel is a promising material for conformance control in hydrocarbon reservoirs. However, its use in low-permeability reservoirs is limited by the high polymer concentrations present. In this study, the gelation performance of an HPAM/PEI system with HPAM < 2.0 wt.% was systematically investigated. The gelation time for HPAM concentrations ranging from 0.4 to 2.0 wt.% varied from less than 1 h to 23 days, with the highest gel strength identified as grade H. The hydrodynamic radius manifested the primary effect of HPAM on the gelation performance. Branched PEI provided superior gelation performance over linear PEI, and the gelation performance was only affected when the molecular weight of the PEI varied significantly. The optimal number ratio of the PEI-provided imine groups and the HPAM-provided carboxylic acid functional groups was approximately 1.6:1~5:1. Regarding the reservoir conditions, the temperature had a crucial effect on the hydrodynamic radius of HPAM. Salts delayed the gelation process, and the order of ionic influence was Ca2+ > Na+ > K+. The pH controlled the crosslinking reaction, primarily due to the protonation degree of PEI and the hydrolysis degree of HPAM, and the most suitable pH was approximately 10.5. Plugging experiments based on a through-type fracture showed that multi-slug plugging could significantly improve the plugging performance of the system, being favorable for its application in fractured low-permeability reservoirs.

Study on a Strong Polymer Gel by the Addition of Micron Graphite Oxide Powder and Its Plugging of Fracture.

It is difficult to plug the fracture water channeling of a fractured low-permeability reservoir during water flooding by using the conventional acrylamide polymer gel due to its weak mechanical properties. For this problem, micron graphite powder is added to enhance the comprehensive properties of the acrylamide polymer gel, which can improve the plugging effect of fracture water channeling. The chemical principle of this process is that the hydroxyl and carboxyl groups of the layered micron graphite powder can undergo physicochemical interactions with the amide groups of the polyacrylamide molecule chain. As a rigid structure, the graphite powder can support the flexible skeleton of the original polyacrylamide molecule chain. Through the synergy of the rigid and flexible structures, the viscoelasticity, thermal stability, tensile performance, and plugging ability of the new-type gel can be significantly enhanced. Compared with a single acrylamide gel, after adding 3000 mg/L of micrometer-sized graphite powder, the elastic modulus, the viscous modulus, the phase transition temperature, the breakthrough pressure gradient, the elongation at break, and the tensile stress of the acrylamide gel are all greatly improved. After adding the graphite powder to the polyacrylamide gel, the fracture water channeling can be effectively plugged. The characteristics of the networked water flow channel are obvious during the injected water break through the gel in the fracture. The breakthrough pressure of water flooding is high. The experimental results are an attempt to develop a new gel material for the water plugging of a fractured low-permeability reservoir.

Prospects for the use of flow diverter technologies at the Alibekmola oil field

Background: The process of oil production from low-permeability reservoirs has some features and is associated with a number of problems. The main problem is the lack of involvement in the active development of oil reserves in low-permeability zones. Most design documents for the development of low-permeability carbonate reservoirs recommend conventional water injection, which leads to rapid water encroachment of production wells due to water breakthrough from the injection well to the production well through the high-permeability layers or fractures.&#x0D; Aim: In the conditions of low-permeability reservoirs of carbonate deposits, there is a need to search for new technologies and development methods that will ensure the economic viability of field development at a late stage.&#x0D; Materials and methods: One of the promising technologies that help reduce the level of water cut and involve in the development of an inactive matrix zone low-permeability fractured reservoirs are flow diverter technologies aimed at increasing the sweeping efficiency of productive formations by redistributing filtration flows, reducing or stabilizing water cut, reducing the volume of produced water, obtaining additional oil production.&#x0D; Results: This article presents the results of laboratory studies on the selection of optimal flow diverter chemical compositions for the conditions of the Alibekmola oil field.&#x0D; Conclusion: Conducted laboratory studies prove the applicability and effectiveness of flow diverter compositions for the conditions of carbonate fractured reservoirs.

Experimental investigation of CO2 foam flooding-enhanced oil recovery in fractured low-permeability reservoirs: Core-scale to pore-scale

Fractured low-permeability reservoirs are characterized by poor reservoir physical properties, strong interlayer heterogeneity and the existence of natural and artificial fractures, resulting in significant water or gas channeling during flooding development. CO2 foam can effectively control the mobility of CO2 and ensure a more stable flooding front. In this study, taking into account the imbibition effect of the flooding process, the flooding performance under different injection methods and the influencing factors of foam pre-injection volume, back pressure and fracture complexity on CO2 foam flooding were systematically analyzed using fractured low-permeability core flooding experiments. In addition, the mechanism of CO2 foam flooding enhanced oil recovery (EOR) in low-permeability fractured reservoirs was obtained in combination with microscopic flooding experiments. The results show that the maximum recovery of 59.36 % can be obtained by soaking the core samples for 12 h with pre-injection of 0.4 PV CO2 foam followed by CO2 foam flooding, which adequately considers the imbibition effect during the flooding process. The pressure difference and oil recovery increases with increasing foam pre-injection amount, and the oil recovery with back pressure (2 MPa and 4 MPa) is significantly higher than that without back pressure; however, a further increase in back pressure has less impact on the recovery. The oil recovery rate of the fracture-free core is lower than that of the multiple fracture core during CO2 foam flooding but higher than that of the single fracture core, and the fracture complexity of the fractured cores has less impact on the final oil recovery. Microscopic experiments show that CO2 foam can effectively prevent channeling and improve the sweep efficiency. Soaking during the CO2 foam flooding process makes foam enter the matrix through the fracture, and CO2 dissolves after the foam breaks to increase the mobility of the crude oil, while the surfactant solution emulsifies the crude oil and changes the rock wettability. The unbroken foam can increase the sweep range, and the crude oil that flows into the fracture is carried by the subsequent injected foam to be recovered as foamy oil.

Numerical Simulation Study on Parameter Optimization of In-depth Fluid Diversion in Low-permeability Fractured Reservoir

Daqing Chaoyanggou Oil Field is a low-permeability fractured oil reservoir that has entered into the middle and high water-cut periods of waterflooding extraction. Now, the moisture content is 74.88% and the injected water flows along fractures. The moisture content of oil wells increases quickly, accompanied with relatively serious invalid waterflooding. The in-depth fluid diversion can be used to exploit residual oil in substrate effectively and thereby increase recovery efficiency of the low-permeability fractured oil reservoir. In this study, parameters of in-depth fluid diversion in low-permeability fractured reservoirs can be optimized by numerical simulation method. According to geologic characteristics and fracture development situations in the study area, a geologic model of the study area was constructed. A historical fitting of exploitation indexes was carried out to optimize the dosage, injection rate and injection time of control-displacement agent during in-depth fluid diversion. Results demonstrated that the optimal dosage, the optimal injection rate and the optimal injection time of the control-displacement agent were 0.1 ∼ 0.15PV, 0.03 ∼ 0.04PV/a and about 70% of comprehensive moisture content, respectively. This study can provide reference to residual oil recovery in low-permeability fractured reservoirs during middle and high water-cut periods.

Experimental study on CO2 flooding characteristics in low-permeability fractured reservoirs

ABSTRACT CO2 flooding in oil reservoir is a complex process, which includes fluid flow in fractured sandstone and interaction of CO2 and displaced oil. In order to thoroughly understand the CO2 flooding characteristics in low-permeability fractured reservoirs, a series of CO2 flooding experiments were conducted based on the multi-field coupling experimental system. Considering the difference of the fractured cores, pore cores and pore-fracture model, the effect of fracture, injection pressure, CO2 phase, and heterogeneity of horizontal composite on the CO2 flooding were analyzed. The results show that the oil recovery of fractured core was 46.96%, 7.13% higher than that of pore core, and there was no relatively stable gas-oil ratio (GOR) stage. For the pore-fracture model, the final recovery of two models increased from 49.45% to 45.86% at 2 MPa to 78.83% and 77.35% at 8 MPa, and the pore core was the main contributor to enhance oil recovery. The supercritical CO2 (sc-CO2) enhanced the oil recovery in post-gas breakthrough state, which accounted for final recovery 65.02%. Compared with the vertical layered heterogeneity, the horizontal composite heterogeneity had less influence on the final oil recovery, with differences of below 2%, and the highest CO2 utilization rate was occurred at the permeability model of Low-High-Low. The work provides insight on oil recovery improvement of CO2 flooding in low-permeability fractured reservoirs.

The Research and Application of Adjustable Drive Improve Oil Recovery Technology in Ansai Low Permeable Fracture Reservoir

In order to solve the serious problem that the injected water channeling is serious and water flooding effect is getting worse in Ansai low permeability fractured reservoir. Developed the gelling movable gel profile control displacement-agent RD which Can control the gel time and the strength. Select out the surfactant XSY-1 that can reduce water interfacial tension to ultra-low and can significantly improve oil displacement efficiency. Designed five group profiling experiments on parallel cores, optimized movable frozen rubber slug of surfactant slug best combination of 0.2 of the PV profile control agent add 0.40 PV surfactant, compared with the water flooding ways to enhance oil recovery of 22.5％ . Adjustable drive combined with technology is the effective way to improve the Ansai low permeability fractured reservoir water flooding effect.

Enhanced oil recovery in fractured low-permeability reservoirs by a novel gel system prepared by sustained-release crosslinker and water-soluble thixotropic polymer

Polymer gels have been widely used in improving oil recovery and decreasing excessive water production in heterogeneous reservoirs after the long-term water flooding process. However, the high initial viscosity of polymer and the short gelation time still restricts the performance of polymer-based in situ cross-linked gels for in-depth conformance control. Herein, a novel gel system formed by in-situ crosslinking of water-soluble thixotropic polymer (WTP) and sustained-release crosslinker (SRC) was proposed. The WTP was synthesized by acrylamide, 2-acrylamido-2-methylpropanesulfonic acid, and N-[3-(dimethylamino)propyl] methacrylamide. It exhibits low viscosity under high shear rates and becomes thick under low shear rates, which ensures good injectability during the injection process and high gelation strength after cross-linking. The SRC was prepared by coating poly(ethyleneimine) (PEI) into the W/O/W multiple emulsions. The sustained-release mechanisms were well elaborated by confocal laser scanning microscopy (CLSM) observations. Only after the demulsification of multiple emulsions, the PEI would be released from the internal aqueous phase to the external aqueous phase. Therefore, these emulsions can be employed to deliver crosslinkers to specified targets in deep regions and prolong the release of crosslinkers to prevent undesirable crosslinking reactions near the injecting wells. According to the environmental scanning electron microscope (ESEM) observations and viscosity measurements, the low viscosity and an incompact spatial network could be observed in SRC/WTP gel system in the first 17 d, after which the PEI molecules were released to the external aqueous phase and cross-linked with WTP, forming the solid gel with small pores and yielding a high viscosity of 8793 mPa⋅s. Rheology tests have demonstrated that the elastic modules and the liner viscoelastic region of the novel gel system was nearly two times and twenty times than the traditional polymer gel, indicating higher gelation strength and better shear resistance. The core flooding tests showed that the SRC/WTP gel system had good injectability and could effectively plug the millimeter and submillimeter-sized cracks in low-permeability cores. 0.6 pore volume (PV) of SRC/WTP gel system with 3 gel slugs and a low injection rate can yield the best plugging performance in fractured core samples. And the gelation time shortens with the decrease of fracture apertures. Most importantly, the field tests in Ordos Basin verified the desirable EOR performance of the SRC/WTP gel system in fractured low-permeability reservoirs.

Numerical Simulation of the Microscopic Plugging Mechanism and Particle Flow Process of the Microsphere System.

The microsphere system has small initial particle size, excellent swelling performance, simple manufacturing process, and strong plugging ability. It has great application potential in the field of plugging and profile control of deep reservoirs. Microspheres can effectively plug the pores of fractured cores, inhibit the rapid breakthrough process, and improve the sweep efficiency of the injected fluids. However, the microscopic plugging mechanism of microspheres on fractured cores is still unclear. In this study, the distribution of microspheres after plugging was observed through specially prepared core models. Furthermore, the microscopic plugging mechanism of microspheres in fractured reservoir cores was clarified, including direct microsphere plugging, cluster bridging plugging, adhesion plugging, extrusion-deformation plugging, and extrusion-crushing plugging. Then, particle flow simulation software was used to establish the fluid-solid coupling model of microsphere plugging, and then, the numerical simulation of the plugging process was realized by Python module programming. Through this study, the plugging effect of microspheres under different fracture opening conditions was clarified. Moreover, the effects of injection pressure difference, fracture width, and particle size ratio on the fluid-solid structures of microsphere plugging were analyzed. The results show that the smaller the particle size ratio, the greater the injection pressure difference, the fracture width, and the reduction magnitudes in fracture porosity and core permeability and the higher the plugging rate. The numerical simulation results well support the microsphere plugging mechanism obtained by experiments. The results of this study can provide theoretical and technical support for the development of deep profile control and flooding and enhanced oil recovery technology of the polymer microsphere dispersion system in fractured low-permeability reservoirs.

Compatibility Evaluation of In-Depth Profile Control Agents for Low-Permeability Fractured Reservoirs.

Under the background that the in-depth profile control technology is gradually applied in low-permeability fractured reservoirs, this paper regards block H of Changqing Oilfield as the research object, referring to the range of its physical parameters and field application data. Three common in-depth profile control agents (PCAs), nanosphere suspension, poly(ethylene glycol) single-phase gel particle (PEG) and cross-linked bulk gel and swelling particle (CBG-SP), are selected to investigate the compatibility between the fractured channels and the PCAs through a series of experiments. The experimental results show that the nanospheres with particle sizes of 100 nm and 300 nm have good injectivity and deep migration ability, which remains the overall core plugging rate at a high level. The residual resistance coefficient of 800 nm nanospheres decreases in a “cliff” manner along the injection direction due to the formation of blockage in the front section, resulting in a very low plugging rate in the rear section. The injection rate is an important parameter that affects the effect of PEG in the fractured channels. When the injection rate is lower than 0.1 mL/min, the plugging ability will be weakened, and if the injection rate is higher than 0.2 mL/min, the core plugging will occur. The appropriate injection rate will promote the better effect of PEG with the plugging rate > 90%. The average plugging rate of CBG-SP in fractured rock core is about 80%, and the overall control and displacement effect is good. Based on the experimental data of PCAs, the optimization criteria of slug configuration and pro-duction parameters are proposed. According to the principle “blocking, controlling and displacing”, references are provided for PCAs screening and parameters selection of field implementation.

The Influence of Pore Structure of the Core-Scale Fracture-Controlled Matrix Unit on Imbibition: Model Construction and Definition of the Fractal Coefficient

Abstract Imbibition oil recovery plays an important role in the development of low-permeability fractured reservoirs. However, the effects of the complex pore structure of the matrix on imbibition have not been considered comprehensively at different scales in the scientific literature. This paper reports a study of the mechanisms of influence of different matrix pores on imbibition recovery ratio and defines the concept of a fractal coefficient using the method of combining numerical simulation at the core scale with mathematical methods at a pore scale. A matrix model with different pore fractal dimensions and tortuosity of the capillary was established using Python language programming. Y-type and S-type were used to characterize the fractures, and a two-dimensional fracture-controlled matrix unit core-scale numerical model with complex pore structures was established. Based on phase field theory, an oil-water two-phase imbibition numerical simulation was conducted. Comparisons of numerical simulation results and microscopic analysis indicated that imbibition recovery ratio was 39.28% and 50.94%, respectively. The imbibition law revealed by the numerical simulation results is consistent with the results of the microscopic imbibition experiment, and the imbibition effect of bifurcated fractures was better than that of simple curved fractures. As the pore fractal dimension and tortuosity of the capillary increased, the imbibition recovery ratio decreased. A comparison of results of the mathematical model demonstrated that there was a difference between the pore scale and core scale because the pore fractal dimension and capillary tortuosity changed dynamically with pore structure at the core scale. Thus, a parameter that characterizes the relative change of pore fractal dimension and tortuosity was defined and called the fractal coefficient. When the skeleton particles are 200, 400, and 500, the fractal coefficient were calculated to be 0.625 and 0.6, respectively, indicating that when the pore structure changes, the imbibition recovery ratio should be dominated by capillary tortuosity.

Imbibition oil recovery of single fracture-controlled matrix unit: Model construction and numerical simulation

The fracture-controlled matrix unit is commonly found in low-permeability fractured reservoirs. Due to the permeability difference between the fracture system and the matrix system, a large amount of oil will remain in the matrix during traditional water injection development, thus limiting reservoir productivity. However, the special imbibition mode of the fracture-controlled matrix unit provides a breakthrough for secondary oil recovery. In this paper, based on the model of single fracture-controlled matrix unit, the dynamic production process of fractured reservoir is studied by the numerical simulation method. The numerical simulation of the imbibition oil production is carried out on the two-point well model by using the method of huff and puff injection. The results show that imbibition is the main mechanism in the middle and late stages of oil recovery from fractured reservoirs. The water in the fracture is absorbed into the matrix by capillary force and the oil is replaced; in this way, imbibition can increase the recovery rate by 20%. The findings provide a basis for the further study of the fracture-controlled matrix unit and imbibition. Cited as: Liu, Q., Liang, B., Liu, J., Sun, W., Lei, Y. Imbibition oil recovery of single fracture-controlled matrix unit: Model construction and numerical simulation. Capillarity, 2022, 5(2): 32-40. https://doi.org/10.46690/capi.2022.02.02