Ultra-low Permeability Research Articles

Numerical investigation of interactions between hydraulic and pre-existing opening-mode fractures in crystalline rocks based on a hydro-grain-based model

Hot dry rock (HDR) is deep geothermal reservoir rock predominantly containing granite, whose physical and mechanical properties are governed by heterogeneous crystal structures. However, the fluid conductivity of intact granite with ultra-low permeability cannot be reformed using existing techniques. Complex fracture networks must be created by connecting hydraulic fractures with natural fractures developed in reservoirs. In this study, we introduce the wall barrier method into the novel hydro-grain-based model (hydro-GBM) to build a prefractured granite model at the mineral grain scale. This model enables investigation of the effects of the stress environment, mineral spatial distribution, and fluid injection rate on hydraulic fracturing characteristics. Microcracks around the inner tips of pre-existing fractures reproduce the initiation, propagation, and coalescence behaviors similar to experimental results. Mineral spatial distributions induce random changes in the propagation paths of hydraulic fractures. Increasing the fluid injection rate delays the deflection of hydraulic fractures and extends the propagation distance along the major axes of pre-existing fractures. The average activity level and proportion of large seismic events are reduced by injecting low-rate fluid. In summary, our results reveal the interactions between hydraulic and pre-existing fractures and provide a valuable reference for constructing an efficient enhanced geothermal system (EGS) for deep reservoirs.

Quantifying the influence of fracture parameters on flow behavior and pressure propagation in complex networks of discrete fractures within low-permeability reservoirs

Fractures in low and ultra-low permeability reservoirs create a complex network, affecting fluid flow patterns and pressure propagation. However, limited research exists on fluid flow patterns and the impact of fracture properties on pressure within these networks. To address this, we introduce fracture shadow area and fracture penetration ratio concepts derived from studying single fracture reservoirs. Using a sophisticated model of a complex fracture network, we analyze how various fracture properties influence fluid flow patterns and reservoir pressure. Fractures are classified into five categories based on the development level. Through orthogonal experiments and multiple regression methods, we derive a formula that quantifies the pressure influence. We find that longer and denser cracks enhance fluid exchange and pressure propagation capacity. Moreover, increasing crack opening expands the area of pressure drop. Notably, fractures aligned with pressure propagation significantly decrease reservoir pressure. The hierarchical sequence of crack traits with the greatest influence is identified as crack length, crack opening, crack density, and crack angle. Our findings shed light on the intricate relationship between fracture properties and pressure dynamics.

Reservoir Characteristics and Development Model of Subaqueous Pyroclastic Rocks in a Continental Lacustrine Basin: A Case Study of the Chaganhua Subsag in the Changling Fault Depression, Songliao Basin

Industrial oil and gas eruptions underwater have been found in the pyroclastic rocks of the Huoshiling Formation in the continental lacustrine basin of the Changling fault depression, Songliao Basin. This paper investigates the reservoir space characteristics, physical characteristics, and pore structure differences of subaqueous pyroclastic reservoirs in the Huoshiling Formation, and the causes of physical property differences of different types of reservoirs and their formation and evolution processes are analyzed. (1) The content of volcanic glass in tuff is higher, the reservoir space is dominated by devitrification pores and dissolution pores, and the coarser the grain size, the more favorable the physical properties, with larger pore sizes and higher porosities. The content of clay minerals in sedimentary tuff is high, the pores between clay minerals are the main pores, and the physical properties of sedimentary tuff are poor. The content of soluble components such as feldspar, debris, and laumontite is high in tuffaceous sandstone, which is dominated by dissolution pores. (2) Primary pores are not developed in the pyroclastic reservoirs in the study area, and the reservoirs are relatively dense, with an average porosity of 2.43% and an average permeability of 0.076 mD. The coarse-grained tuff has the highest porosity, followed by tuffaceous sandstone and fine-grained tuff, and the sedimentary tuff has the least favorable physical properties. (3) Devitrification was an important cause of the high-porosity and ultralow permeability of tuff reservoirs. Two oil and gas charges in the middle diagenetic stage led to the organic acid dissolution of rocks. In addition, fractures can provide migration channels for organic acids and deep hydrothermal fluids, leading to late dissolution, and can connect various scattered dissolution pores to improve the effectiveness of the reservoir space. (4) Coarse-grained tuff reservoirs that developed in the proximal facies are favorable targets for hydrocarbon exploration.

Flowback and early-time production modeling of unconventional gas wells using an improved semi-analytical method

Multiple fractured horizontal wells (MFHWs) currently are the only possible means of commercial production from the low and ultra-low permeability unconventional gas reservoirs. In early production time, flowback fluid, which constitutes of hydraulic water and gas flow within fractures, is collected and analyzed. Flowback analysis has been shown to be a useful tool to estimate key properties of the hydraulic fracture such as conductivity and pore volume. Until date, most tools of flowback analysis rely on empirical and approximate methods. This study presents an improved Green-function-based semi-analytical solution for performance analysis of horizontal gas wells during flowback and early production periods. The proposed solution is derived based on coupling the solutions of two domains: a rigorously derived Green’s function-based integral solution for single-phase gas flow in matrix, and a finite-difference, multiphase solution for gas–water two-phase flow in the fracture. The validity of proposed semi-analytical solution is verified by finely gridded numerical models built in a commercial simulator for a series of synthetic cases considering a variety of fluid and reservoir property combinations, as well as various different production constraints. Comparisons against available empirical and approximate methods are also provided for these cases.

High pressure air injection in ultra-low permeability reservoirs: Effects of physical and chemical reactions on oil recovery

This research aims to investigate the effects of physical and chemical reactions on oil recovery during high-pressure air injection (HPAI) in ultra-low permeability reservoirs. The oxidation reaction characteristics of dead oil were investigated using thermal analysis experiments and oxidation tube experiments. Additionally, pressure-volume-temperature (PVT) analysis was employed to simulate the physical and chemical reactions between air and live oil under formation conditions. The results indicated that the fuel deposition (FD) stage exhibited less prominence in light oil due to its lower content of resins and asphaltenes. Additionally, the presence of cuttings impeded the volatilization of lighter components during low-temperature oxidation (LTO) stage, effectively storing fuel required for subsequent high-temperature oxidation (HTO) stage, consequently facilitating a direct transition from LTO to HTO. Notably, the debris derived from the ultra-low permeability reservoirs possesses an enlarged specific surface area, facilitating enhanced contact between the oil and oxygen. This heightened contact effectively reduces the activation energy required for the LTO stage by an appreciable 22.9 kJ/mol. Furthermore, the PVT experiments reveals a quadratic relationship between pressure and viscosity, while a cubic relationship exists between pressure and the expansion rate of crude oil. Moreover, the thermal effects of oxidation reactions and the dissolution of the gas phase have been found to exert a more substantial influence on reducing oil viscosity, in contrast to the oxygen addition reaction and the extraction of lighter components, which have a minor influence on increasing oil viscosity. Lastly, in the context of developing HPAI techniques for ultra-low permeability reservoirs, optimizing the gas injection rate emerges as a viable strategy to effectively enhance oil recovery, provided that the occurrence of gas channeling is effectively mitigated.

Experimental study on stress-dependent multiphase flow in ultra-low permeability sandstone during CO2 flooding based on LF-NMR

Oil production performance in the unconventional reservoirs is significantly affected by the flooding agent and occurrence environment. In this study, the in-situ stress and displacement pressure effects are considered, the response of CO2/Oil and pore structure was monitored by online low field nuclear magnetic resonance (LF-NMR). The results show that the pore structure was composed of adsorption pore (AP＜3 m s), percolation pore (3 m s＜PP＜30 m s), and migration pore (30 m s＜MP). The stress sensitivity of adsorption pore is more obvious than that of percolation pore and gradually weakened responding to the increase of in-situ stress. The increased in-situ stress narrowed and closured pore throats and limited the migration of CO2/Oil, and the pore transformed from gas-channeling type into homogeneous type and the hydraulic conductivity of CO2 and oil decreased non-linearly responding to the pore shrinkage. The percolation pore and migration pore dominate the oil recovery, and the decreased MP resulted in the non-linearly and dynamic reduction of oil recovery. The higher relative permeability was presented and the end-point oil saturation non-linearly increased with the increasing in-situ stress. The increased displacement pressure effectively improved the oil recovery and dynamic gas channeling, and the incremental oil recovery was primarily contributed by the PP and MP due to the increased CO2 swept area. The positive effect of displacement pressure on oil recovery gradually reduced with the increase of in-situ stress. The findings provide a significant insight on the application of CO2-EOR in ultra-low permeability reservoirs.

Development characteristics and genesis of deep tight conglomerate reservoirs of Mahu area in Junggar Basin, China

To clarify the development rules and main origins of deep tight conglomerate reservoirs in the Mahu area of Junggar Basin, various materials and data from deep wells were systematically researched to determine the reservoir's basic characteristics and effective origins. The results indicate that the reservoir mainly comprises a fine and medium-fine conglomerate, which belongs to the fan delta distributary channel conglomerate. Additionally, it is a typical deep tight conglomerate reservoir with low to ultra-low porosity and permeability, and the gravel primarily consists of volcanic rock composed of tuff and intermediate acid volcanic lava. The cement is mainly composed of laumontite and calcite, and the reservoir has undergone three types of diagenesis: compaction, cementation, and dissolution. The first two types have dual effects of destruction and construction, while the result of dissolution is the widespread development of secondary pore enrichment zones composed of intergranular solution pores formed by the dissolution of zeolite, carbonate cement, and argillaceous matrix, as well as intragranular solution pores formed by the dissolution of feldspar and dark minerals. Unlike the middle and shallow layers, the reservoir space mainly composed of secondary pores and fractures. The effective reservoir is mainly caused by rock composition, dissolution, fracture system, and abnormal high pressure. The rock composition provides a sufficient material basis and is the internal cause, while the dissolution, fracture system, and abnormal high pressure are the external causes. The dissolution forms a secondary pore enrichment zone, the fracture system improves the seepage capacity of the reservoir, and abnormal high pressure can effectively maintain and increase the pores. Four factors control the formation and distribution of relatively high-quality deep tight conglomerate reservoirs.

Preparation and application of modified carbon black nanofluid as a novel flooding system in ultralow permeability reservoirs

Conventional flooding systems have very low recovery rates in ultralow permeability reservoirs in virtue of the characteristics of high injection pressure, low permeability and small pores in such reservoirs. In this study, a novel surface-modified carbon black (MCB) nanofluid was prepared as a flooding system to resolve this problem. The preparation process of MCB nanoparticles was divided into three stages: (1) oxidation of carbon black (CB) nanoparticles, (2) acyl chlorination of oxidized carbon black (OCB) nanoparticles and (3) grafting of active groups onto the surface of acyl chloride carbon black (ACB) nanoparticles, and the main synthesis conditions, such as modifier concentration and grafting temperature, were optimized. X-ray photoelectron spectroscopy (XPS) and X-ray diffraction (XRD) analysis indicated that the factional groups were successfully introduced onto the surface of CB nanoparticles, and the crystallinity of CB nanoparticles decreased gradually during the reaction process. Additionally, the dispersed stability, temperature resistance, salinity tolerance, wettability alteration and oil stripping ability were evaluated so as to obtain the performance of the MCB nanofluid. The results show that the average size of the MCB nanoparticles is approximately 72.3 nm, and the dispersed stability of the MCB nanofluid is much better than that of the CB nanofluid. Compared with the carbon black (CB) nanofluid, the MCB nanofluid shows stronger wettability alteration and oil stripping ability, and can also withstand the high temperature and high salt environment of oil reservoirs. 1 PV of MCB nanofluid can enhance oil recovery by 28.9%. Furthermore, the enhanced oil recovery (EOR) mechanisms for the MCB nanofluid are revealed through analysis of low oil–water IFT (IFT), wettability alteration and Wasan’s theory of structural disjoining pressure. This new type of environment-friendly flooding system injects vitality into the development of ultralow permeability reservoirs.

Microscopic Analysis of Natural Fracture Properties in Organic-Rich Continental Shale Oil Reservoirs: A Case Study from the Lower Jurassic in the Sichuan Basin, China

Natural fractures are of paramount importance in storing carbon in shale oil reservoirs, where ultra-low porosity and permeability necessitate their essentiality for enhanced oil recovery. Therefore, comprehensively clarifying the characteristics of natural fractures in shale oil reservoirs is imperative. This paper focuses on investigating the microscopic features of natural fractures in organic-rich continental shale oil reservoirs that are commonly found in the Lower Jurassic strata of the Sichuan Basin, employing them as a representative example. Multiple methods were utilized, including mechanical testing, Kaiser testing, multi-scale CT scanning (at 2 mm, 25 mm, and 100 mm scales), and a numerical simulation of fluid seepage in fracture models. The results revealed that the in situ stress of the target seam displays the characteristic of σH > σv > σh, with σv and σh being particularly similar. The relatively high lateral stress coefficient (ranging from 1.020 to 1.037) indicates that the horizontal stresses are higher than the average level. Although the 2 mm CT scan provides a more detailed view of fractures and connected pores, it primarily exhibited more pore information due to the high resolution, which may not fully unveil additional information about the fractures. Thus, the 25 mm shale core is a better option for studying natural fractures. The tortuosity of the different fractures indicated that the morphology of larger fractures is more likely to remain stable, while small-scale fractures tend to exhibit diverse shapes. The simulations demonstrated that the stress sensitivity of fracture permeability is approximately comparable across different fracture scales. Therefore, our research can enhance the understanding of the properties of natural fractures, facilitate predicting favorable areas for shale oil exploration, and aid in evaluating the carbon storage potential of shale oil reservoirs.

Detailed investigation on the oxidation behavior and kinetic triplet of tight oil via TG-DSC-PDSC analyses

It remains some barriers for continental tight oils to enhance oil recovery owing to low or ultra-low permeability in China. Whether low temperature combustion mode (or deflagration fracturing) could be employed to expand the fracture, is an interesting but debatable topic in consideration of the not well-understood oxidation behavior and kinetic mechanism for the tight oil. This study initiated a comprehensive characterization on the oxidation behavior and kinetic triplet for the Mahu tight oil via the combination of atmospheric and pressurized thermal analyses (TG/DTG, DSC/DDSC, PDSC) and unconventional Popescu method. Threshold, peak, and end temperatures were shifted to higher temperature ranges following lower cumulative heat emission (from 13.21 to 9.15 kJ·g−1) with the heating rate increment from 5 to 15 K·min−1. Inversely, a more thorough oxidation process with higher cumulative heat releases (8.69 kJ·g−1 for LTO, 4.48 kJ·g−1 for HTO) was presented under elevated pressure condition. In order to elucidate the latent reaction mechanism, seven sequential temperature subzones were divided to acquire the most probable mechanism function G(α) and corresponding kinetic parameters. The results indicated that, owing to the high reservoir pressure, generated enormous heat in LTO stage had a significant acceleration to initiate and sustain the low temperature combustion process, which in some degree was conducive to update and expand the understanding of the low temperature in-situ combustion mode of air injection in low permeability and tight oil reservoirs via fracturing reservoir matrix.

Effective Water Injection Development Test for Rolling Outward Expansion of Low-grade Reservoir

The development of ultra-low permeability reservoirs in the oilfield mainly involves a large proportion of ultra-low permeability and it is difficult to recover reserves because of scattered distribution, low reserve abundance, poor reservoir physical property, and great development difficulty as well as low production intensity, rapid production decline, and low stable production of oil wells. In order to speed up the development of undeveloped reserves and explore the effective technical approach to solve problems in low permeability and difficulty in recovering reservoirs, we carried out the effective water injection development test in the B1 test area. In this paper, in-depth research has been carried out in reservoir geological understanding, development well pattern design optimization, and advanced water injection technology research. Finally, a set of effective production technologies for low abundance reserves in complex geological conditions are formed, effective production in B1 Block that was hard to recover reserves is realized, the drilling success rate is improved greatly, and well pattern design optimization is achieved, advanced water injection efficient development technologies for low abundance reserves blocks are also developed. The demand for rolling production can be gradually extended to other oilfields, which has certain reference significance for the development practice of peripheral oilfields and similar small complex fault block oilfields.

A new apparatus for investigating gas transport property in geomaterials with ultralow permeability

The gas flow in geological materials with ultra-low permeability can vary dramatically, i. e., from almost no measurable quantity of gas before breakthrough to a massive gas flux at breakthrough. It is a great challenge to realize the whole process measurement of gas transport in saturated geomaterials with ultra-low permeability. In this work, a newly designed temperature-controlled triaxial apparatus was developed. In which, a water-to-gas-exchanger was designed for precise injection of gas at a constant pressure or constant injection rate, due to that water is less compressible and much more difficult to leak through the seal of a regulator. Meanwhile, eddy current sensors and displacement transducer with high resolutions were utilized to accurately measure the specimen deformation at different locations in a non-contact way to explore the mechanism of gas entry and breakthrough. In addition, a gas flow detection device that contains four gas flowmeters with different measurement ranges and can automatically switch between these flowmeters was developed to monitor the gas outflow of the whole process. To validate the performance of the developed apparatus, systematic gas injection tests on Gaomiaozi (GMZ) bentonite were conducted, during which the helium gas was injected in a constant rate. Real-time data on inlet gas pressure, gas outflow rate, stress state (both isotropic and axial stresses) and volume deformation (both axially and radially) were monitored. Results show that the developed apparatus could successfully capture the gas entry and the subsequent breakthrough points of the compacted bentonite with ultralow permeability. For compacted bentonite with high saturation, capillary flow, dilatant flow and interfacial leakage could co-exist during the gas transport process and the dominated mechanism was closely related to the gas injection pressure.

EOR mechanism of fracture oil displacement agent for ultra-low permeability reservoir

Due to the low permeability, small pore throat, and poor pore connectivity of ultra-low permeability reservoirs, fracturing was required to improve the flow environment of oil in the reservoir during its development. The combination of fracturing and oil displacement could reduce the complexity of the development of ultra-low permeability reservoirs. It was feasible to synthesize new surfactants to prepare fracturing oil displacement agents, but the research and development of new surfactants were difficult and costly. This paper aimed to experimentally investigate the imbibition displacement mechanism of fracturing flooding by combining the surfactant of chemical flooding with the fracturing fluid. With the conditions of the ultra-low permeability reservoir in block Y of Changqing Oilfield, the mechanism of remaining oil start-up and fractured oil displacement agent enhanced oil recovery in the ultra-low permeability reservoir was studied by microfluidic model experiment and NMR experiment. A mixture of fracture oil displacement agents was obtained by mixing heavy alkyl benzene sulfonate surfactant, a nonionic surfactant, and a betaine-type amphoteric surfactant. HAS-6C, HAS-5E, and HAS-5G were selected for their interfacial tension reaching 10−3 mN/m. Oil–water​ interfacial tension of HAS-5E was the lowest, which can be reduced to 10−4 mN/m. The ability to alter the wettability of HAS-6C was the most significant, which could make the contact angle go down to 64.5°. The multi-round dynamic and static imbibition experiments showed that the combination of selected surfactant and slickwater can greatly improve the imbibition recovery, of which HAS-6C could enhance oil recovery by 17%. The HAS-5E system with the lowest interfacial tension had the best effect of starting clustered residual oil, and the clustered residual oil saturation was reduced by 48.8%. The HAS-6C system with stronger wettability had the best effect of starting throat-like residual oil, and the throat-like residual saturation was reduced by 10.8%.

Influences of confining pressure and injection rate on breakdown pressure and permeability in granite hydraulic fracturing

AbstractHot dry rock (HDR) geothermal resource is a renewable green energy source with great exploitation potential. The burial depth of HDR generally exceeds 2500 m and is typically under high in situ stress conditions, resulting in an ultralow permeability of the rock formations. To enhance the permeability of these formations, hydraulic fracturing is widely used as a reservoir stimulation technique in HDR geothermal resource exploitation. The differences in burial depth, in situ stress, and geological environment require different engineering designs when implementing hydraulic fracturing. Therefore, the confining pressure and injection rate play significant roles in determining the effectiveness of hydraulic fracturing, as they affect the propagation and distribution of fractures in the rock formation. To quantify the impact of these factors on the effectiveness of hydraulic fracturing, simulation experiments, and permeability tests were conducted using granite specimens under various confining pressure and injection rate conditions. The results of these experiments revealed the relationships among the confining pressure, injection rate, breakdown pressure, and permeability enhancement of the granite. The breakdown pressure of granite increased with the confining pressure, while the injection rate had little effect on the breakdown pressure. The hydraulic fractured sample produced new penetrating fractures, which increased the reservoir permeability, and owing to the higher complexity of hydraulic fractures under low confining pressure, the increase of permeability is correspondingly higher. The research results can provide an important reference for efficient stimulation development technology of deep HDR geothermal resources.

Experimental Investigation on Flow Resistance Reduction of Nanofluid in Ultralow Permeability Reservoirs: Performance and Mechanism

Ultralow permeability reservoirs have small pore throats, poor pore connectivity, and large water injection resistance. When nanofluid is injected into the formation, it can effectively reduce water flow resistance. However, there is still no systematic and in-depth study on flow resistance reduction performance and the mechanism of nanofluid in ultralow permeability reservoirs. In this study, the effects of different factors (fluid system, matching coefficient of nanofluid particle size and pore size, injection parameters, and adsorption time) on flow resistance reduction performance of ultralow permeability reservoirs were studied through a core pressure differential driving experiment. When the matching coefficient was 126.5, the content was 0.01 wt %, the injection volume was 0.5 PV, and the adsorption time was 6 h, the percent reduction reached a maximum of 33.4%. The results of the core flow scouring experiment showed that the nanoparticle adsorption strength on the core pore surface was high. The flow percent reduction was maintained at 4.7–44.0% under a waterflooding speed of less than 10 mL/min, and it remained above 40.0% when the subsequent water injection volume reached 100 PV. After nanoparticle adsorption on the pore surface, the surface roughness decreased by 30.7%, and the core surface changed from hydrophilic to hydrophobic (oil phase contact angle decreased from 140.1° to 35.5°), which resulted in a hydrophobic sliding effect and effectively reduced water flow resistance. Overall, this study provides a theoretical basis and technical support for nanofluid applications in flow resistance reduction and injection enhancement of ultralow permeability reservoirs.

Optimization of Hydraulic Fracture Treatment Parameters for Normally Pressured Longmaxi and Wufeng Shales in the Southeastern Sichuan Basin in China

Lower Silurian Longmaxi and Upper Ordovician Wufeng shales are gas-producing formations. These formations have ultralow porosity and permeability in the southeastern Sichuan Basin and have normal formation pressures with pressure coefficients of less than 1.2. Hydraulic fracturing has been proven as the best development strategy to produce gas. But choosing hydraulic fracture treatment parameters becomes challenging due to strong reservoir heterogeneity, significant horizontal stress contrast and high in situ stress in this region. We employed the pseudo-three-dimensional (P3D) model to study fracturing fluid types, injection rates, and proppant sizes to optimize the fracturing design of these shale formations. First, this model was solved in the simulator by the finite element method (FEM) to obtain the fracture height, length, and width. Then the results were validated by 3D Tip dominated model, and the perkins-kern-nordgren (PKN) and khristianovic-geertsma-deklerk (KGD) analytical models, which are popular and most used in designing hydraulic fractures. It was found that as the volumetric injection rate and gel loading in the fracturing fluid rise, so do the generated fracture length and width. Furthermore, the formations’ stress contrast affected the shape of the fracture, the interval with lower stress had a wider fracture compared to the interval with higher stress. Also, the higher stress in the layers above and below the shale formations contained the fracture height, which favored the growth of fracture in the shale formations. Lastly, it is suggested that a fluid with gel loading of 60 ppgt, proppant with 12/20 mesh size and an injection rate of 6.36 m3/min be used in these shale formations with normal reservoir pressure. These parameters’ combinations created the most extended propped fracture length of 264.8 m, and the average width was 1.06 cm.

Numerical simulation of fracturing and imbibition in shale oil horizontal wells

The shale oil reservoir is characterized by tight lithology and ultra-low permeability, and its efficient exploitation requires the technology of multi-stage and multi-cluster hydraulic fracturing in horizontal wells and shut-in imbibition. After multi-stage and multi-cluster hydraulic fracturing, a complex fracture network is formed, and a large volume of frac fluid is stored within the fracture network. During shut-in, imbibition and exchange between oil and water occurs under the action of the capillary force and osmotic pressure, and the formation pressure builds up in the shale reservoir. On basis of the characteristics of shale oil reservoir, we establish a model of imbibition during fracturing injection and shut-in by coupling oil–water two-phase flow and saline ion diffusion in the hydraulic fractures (HFs) network, natural fractures (NFs) and matrix system under the action of capillary force and osmotic pressure. The DFN method and the multiple continuum method are introduced to characterize fluid flow between the HF and the NF and that between the NF and the matrix respectively, which avoids the problem of a large amount of computation of seepage within the complex fracture. Then, the discrete fracture network (DFN) model and the multiple continuum model are solved with the finite element method, and it is verified in flow field, saturation field and concentration field that the models are accurate and reliable. We propose the imbibition exchange volume for quantitative evaluation of the imbibition degree and a method of calculating the imbibition exchange volume. Simulation of oil and water flow in the fracturing and shut-in stages is performed based on these models. It is found that imbibition in the shale reservoir is driven by mechanisms of pressure difference, capillary force and osmotic pressure. The osmotic pressure and capillary force only cause an increase in the imbibition rate and a reduction in the imbibition equilibrium time and do not lead to variation in the peak of imbibition exchange volume. The imbibition equilibrium time under the action of the capillary force and osmotic pressure is reduced from 150 to 45 d compared with that under the action of the pressure difference. If imbibition equilibrium is reached, low initial water saturation, strong rock compressibility, high formation water salinity and high matrix permeability enhance imbibition and exchange of oil and water in the reservoir. The leakoff volume of frac fluid is generally larger than the imbibition exchanged volume. Leakoff equilibrium occurs slightly earlier than imbibition equilibrium. The imbibition equilibrium time is mainly affected by reservoir permeability and NF density. The number of interconnected fractures mainly affects the frac fluid volume within the hydraulic fracture in the fracturing process. The stimulated reservoir volume (SRV) mainly affects frac fluid imbibition exchange in the shut-in process.

Sedimentary Facies Evaluation of Tight Oil Reservoirs of Yanchang Formation in the Ordos Basin

Tight sandstone gas has become one of the important unconventional resources. It is of great significance to study the pore throat structure of tight sandstone for the development of tight sandstone gas reservoirs. On the basis of previous research results, this paper studies the tight reservoir characteristics of Yanchang Formation by combining geological data with geophysical logging. The reservoir characteristics are described and studied in detail by ordinary thin section, casting thin section, graphic granularity, and scanning electron microscope experiment. The experimental results show that the reservoir sandstone types of long 6 segments are mainly lithic feldspathic sandstone and feldspathic lithic sandstone, with high component maturity and structural maturity. The components of cement mainly include authigenic clay minerals illite, chlorite, and carbonate minerals. The reservoir space is mainly composed of feldspar-dissolved pores and residual intergranular pores. Compaction and cementation are the decisive factors of pore reduction. At present, the average porosity of the reservoir is 8.33% and the average permeability is 0.12 × 10−3 μm2, which belong to an ultralow porosity and ultralow permeability reservoir. On the basis of studying the origin, superimposition, and distribution of sand bodies and taking into account the sedimentary characteristics, origin, and trigger mechanism of gravity flow, a multisource sedimentary model is established in the study area, which is dominated by sandy debris flow, accompanied by turbidity current and local development of sandy slump. The thick massive sandstone with the most exploration significance in the study area is formed by the superimposition of multistage sandy clastic flow sediments along the gully in the direction of delta to lake. Summarizing the characteristics of reservoir development and evaluating and predicting it can provide geological basis for the next exploration and development of deep-water tight reservoirs in the study area.

Development and Application of New Fracturing Fluid System for Shale Oil Reservoir Displacement

Shale reservoir has tight reservoir, ultra-low permeability and poor development of natural fractures, which need to be completed by fracturing reconstruction. There are some problems in conventional fracturing fluid construction, such as serious reservoir damage, poor salt resistance, inability to reuse flowback fluid, poor dispersion and wetting change performance. According to the characteristics of reservoir and the problems existing in the construction, a hydraulic fracturing fluid system for shale oil reservoir with surfactant as its main component has been developed. There is no residue after the thickener is broken, and the damage to the reservoir is small. It's salt resistant is 100000mg/L, can realize the reuse of flowback liquid and reduce the oil water interfacial tension to 10-3mN/m level because of good dispersion. At present, the application effect is good at the 725 strata of 13 Wells in H100 platform.

Prediction of gas–water relative permeability in tight rock from movable fluid distribution with nuclear magnetic resonance

The measurement of the relative permeability in tight rock is challenging due to its ultralow permeability and the time-consuming nature of the experiments. Studying the movable and unmovable fluid distribution and establishing a reliable relative permeability prediction model is an urgent problem to be solved. This paper used nuclear magnetic resonance (NMR) to investigate movable and unmovable water distribution in tight sandstone under different centrifugal forces. A new method for predicting gas–water relative permeability in tight rock is established based on movable fluid distribution using the capillary bundle model. The results show that the distribution of movable and unmovable fluids is strongly influenced by the tight rock's pore size distribution and structure. The unmovable fluid saturation increases as the tight rock's permeability and median radius decrease. The nonlinear correlation between the NMR relaxation time and the pore throat size obtained from high-pressure mercury intrusion can be used to derive the pore size of the fluid distribution in tight rocks. The ratio of the movable fluid thickness to pore throat size increases near linearly with the logarithm of the pore throat size. The proposed mathematical model for the prediction of gas-water relative permeability based on movable fluid distribution is verified by comparing with the normalized relative permeability curve measured from experiments. This new model offers an alternative method of estimating the gas–water relative permeability when measurement is unavailable due to the ultralow permeability of the core samples.