Unconventional Gas Reservoirs Research Articles

Review on critical liquid loading models and their application in deep unconventional gas reservoirs

The exploitation of deep unconventional gas resources has gradually become more significant attributing to their huge reserves and the severe depletion of convention gas resources in the world. The proportion of deep unconventional gas reservoirs in the total gas resources cannot be underestimated, including shale gas, tight gas, and gas of coal seam. Due to the low permeability and porosity, hydraulic fracturing technology is still an important means to develop deep unconventional gas resources. However, the presence of fracturing fluids and water accumulation at the bottom of the wellbore significantly reduce gas production. The liquid loading model can be used to determine when the gas well begins to load the liquid. In this work, different types of liquid loading models are classified, and the applicability of different models is analyzed. At present, the existing critical liquid carrying models can be divided into mechanism models and semi-empirical models. The model established by Turner is a typical mechanism model. There are great differences in the application of a critical liquid loading model between vertical and horizontal wells. The field cases of a liquid loading model in different gas fields are provided and discussed. The mechanism of liquid loading models in recent years is introduced and analyzed. The physical simulations and experimental work therein are described and discussed to clarify the feasibility of the modeling mechanism. This article also presents the limitation and future work for improving the liquid loading models.

Study on the Interaction Propagation Mechanism of Inter-Cluster Fractures under Different Fracturing Sequences

Horizontal-well multi-cluster fracturing is one of the most important techniques for increasing the recovery rate in unconventional oil and gas reservoir development. However, under the influence of complex induced stress fields, the mechanism of interaction and propagation of fractures within each segment remains unclear. In this study, based on rock fracture criteria, combined with the boundary element displacement discontinuity method, a two-dimensional numerical simulation model of hydraulic fracturing crack propagation in a planar plane was established. Using this model, the interaction and propagation process of inter-cluster fractures under different fracturing sequences within horizontal well segments and the mechanism of induced stress field effects were analyzed. The influence mechanism of cluster spacing, fracture design length, and fracture internal pressure on the propagation morphology of inter-cluster fractures was also investigated. The research results indicate that, when using the alternating fracturing method, it is advisable to appropriately increase the cluster spacing to weaken the inhibitory effect of induced stress around the fractures created by prior fracturing on subsequent fracturing. Compared to the alternating fracturing method, the propagation morphology of fractures under the symmetrical fracturing method is more complex. At smaller cluster spacing, fractures created by prior fracturing are more susceptible to being captured by fractures from subsequent fracturing. The findings of this study provide reliable theoretical support for the optimization design of fracturing sequences and fracturing processes in horizontal well segments.

Fractal Evolution Characteristics on the Three-Dimensional Fractures in Coal Induced by CO2 Phase Transition Fracturing

Fractal Evolution Characteristics on the Three-Dimensional Fractures in Coal Induced by CO2 Phase Transition Fracturing

Optimizing Recovery of Fracturing Fluid in Unconventional and Tight Gas Reservoirs Through Innovative Environmentally Friendly Flowback Additives

Hydraulic fracturing, a method used to stimulate oil and gas from shale and tight formations, faces challenges like fluid blockage and fast declining oil or gas production rates due to the significant impact of capillary forces on water retention. To address this, surfactants and microemulsions are commonly employed as flowback additives to reduce surface and interfacial tension, enhancing water recovery during hydraulic fracturing. The effectiveness of flowback additives is highly impacted by harsh subsurface conditions, such as high salinity and high temperature. This study aims to assess the performance and effectiveness of methylimidazolium chloride-based ionic liquids as flowback additives at high salinities and temperatures.Different experimental analysis were conducted to screen different concentrations of methylimidazolium chloride-based ionic liquids (X1, X2, and X3). Surface tension measurements were conducted to estimate the critical micelles concentrations. A spinning drop tensiometer (SDT) was utilized to measure interfacial tension, in addition, contact angle measurements were used to evaluate the impact of the flowback additive on the wettability and the displacing behavior. Seawater was used as the base fracturing fluid with a salinity of 57,000 ppm and temperatures up to 90°c for all experiments. Coreflood experiments were conducted using tight formations to evaluate the regained hydrocarbon permeability and the fracturing fluid recovery in the presence of flowback additives.Various formulations, with surface tension values ranging from 30 to 45 mN/m and CMC values between 0.5 and 1 gallon per thousand units (gpt), were examined. The lowest interfacial tension value, notably 3 mN/m, was achieved with the X3 formulation. Ionic liquids demonstrated favorable surface tension reduction, where longer carbon chains led to lower values. Introducing diverse ions, especially divalent ions, enhanced the performance of ionic liquids. Interfacial tension measurements indicated a significant reduction with the addition of X3 to both 5 wt% KCl and the fracturing base fluid. Contact angle measurements revealed a shift towards greater water-wettability after treating the rock with flowback additives. Moreover, the use of ionic liquids improved permeability by 25%, enhancing fluid recovery to around 56%.According to our results, methylimidazolium chloride-based ionic liquids can be used as environmentally friendly flowback additives, especially in harsh conditions of high temperature and high salinity where the conventional additives are not suitable. This will contribute to the development of more sustainable and environmentally conscious practices in hydraulic fracturing operations. Ultimately, the utilization of these additives can help mitigate water blockage, reduce formation damage, and enhance shale gas production.

Optimization of Abnormal Hydraulic Fracturing Conditions of Unconventional Natural Gas Reservoirs Based on a Surrogate Model

Abnormal conditions greatly reduce the efficiency of hydraulic fracturing of unconventional gas reservoirs. Optimizing the fracturing scheme is crucial to minimize the likelihood of abnormal operational conditions, such as pressure channeling, casing deformation, and proppant plugging. This paper proposes a novel machine learning-based method for optimizing abnormal conditions during hydraulic fracturing of unconventional natural gas reservoirs. Firstly, the main controlling factors of abnormal conditions are selected through a hybrid controlling analysis, upon which a surrogate model is established for predicting the occurrence probability of abnormal conditions, rather than whether abnormal conditions happen or not. Subsequently, a machine learning-based optimization algorithm is developed to minimize the occurrence probability of abnormal conditions, acknowledging their inevitability during the fracturing process. The optimal results demonstrate the proposed method outperforms traditional methods, on average. The proposed methodology is more in line with the needs of practical operation in an environment full of uncertainty.

Quantitative characterization of thin-interbedded coal measure reservoir configurations in the Wujiu depression, inner Mongolia: Sedimentary controlling mechanisms

Thin-interbedded coal measure reservoirs are important unconventional gas reservoirs. The lithology of these reservoirs is complicated, with rapid vertical changes, making accurate description difficult. Based on the thin-interbedded coal-bearing strata in the Wujiu Depression in eastern Inner Mongolia, China, this study constructs changes in lithofacies based on a Markov mathematical and statistical model. The Shengli subdepression mainly features a lithofacies sequence of uniform coal-mud-sand cycles and other small-scale symmetrical sedimentary cycles. In the Moguai–Shiwalu subdepression, lake hydrodynamics primarily affect coal–mudstone and mudstone–sandstone double-cycle lithofacies sequences and small-scale asymmetric sedimentary cycles. The Markov model and the Ward minimum variance method were used to quantitatively couple a reservoir lithologic sequence and bed thickness configuration, and five basic configurations of the composite reservoir of the Damoguaihe Formation in the study area were obtained: (1) multiseam interbedded configuration, (2) multiseam interbedded configuration with an intermediate number of seams, (3) interbedded configuration with an intermediate number or few seams (with thick mudstone or sandstone layers), (4) interbedded configuration with few seams (large spacings between adjacent coal seams) and (5) thickly interbedded configuration. The sedimentary facies mechanism controlling the spatial distribution pattern of composite reservoirs is discussed. It is concluded that the sedimentary system domain and lake size have a significant effect on the configuration of composite reservoirs. For small terrestrial lakes, the stability of sedimentary environment and the rapid and frequent rise and fall of the lake surface results in significant differences in coal accumulation in a short distance from the edge to the center.

Improved identification of fracture total factor characteristics and cross-scale flow channels by interpreting initial production data of horizontal wells

Fracture identification after hydraulic fracturing of tight gas reservoirs is crucial to fracturing evaluation, productivity analysis, and production plan. Owing to fracture branching, bending, extending, and reversing in reservoirs, a simplified straight fracture cannot fully describe fracture characteristics. The novelty of this study is that the coupling mechanism between the complex fracture network characteristics and well production performances is figured out, thus achieving the identification of fracture morphology in fractured reservoirs. In this study, a combined model including Laplace transform, boundary element method, Stehfest numerical inversion, and fractal theory presents transient well performances. The key contributions to productivities at different production stages are dynamically identified via a sensitivity analysis. The results clearly indicate that the fracture total length is the key factor determining productivities due to no fracture interference at initial production stage. Furthermore, the logarithm of productivity linearly depends on the logarithm of production time and the productivity contribution rate equals the ratio of fracture length to total length. Thus, an updated inversion method is proposed by interpreting initial production data based on a tree-shaped fracture network associated with fracture total factor and cross-scale characteristics. The inversion results well match with their targets, with an error of no more than 5 %, ensuring the accuracy and validity of the proposed method. This innovative approach with low requirements on field data is convenient to yield an accurate prediction of fracture morphology, thereby providing a feasible strategy for promoting sustainable production of clean energy in unconventional gas reservoirs.

Experimental Study on Yield Strength Variation Law of Casing Materials under Alternating Thermal–Mechanical Coupling Loads

Unconventional oil and gas reservoirs, characterized by low porosity and permeability, often require multistage fracturing techniques for development. The high-pressure fracturing fluids with large volumes can easily cause alternating changes in both temperature and pressure within the casing. Using a theoretical model and field data from hydraulic fracturing operations, this paper calculated the alternating ranges of axial loads and temperatures in the reservoir section. Based on the calculation results, the temperature–load alternating coupling test of the P110 casing was carried out, and the tensile test was performed to analyze the yield strength variation law of the casing material. The results indicate that the yield strength, ultimate strength, and elastic modulus of casing materials are decreased under alternating thermal–mechanical coupling conditions. As the number of alternating cycles increases, there is an initial rapid decrease followed by a slower declining trend. Moreover, the tension–tension (T–T) cycles induce greater reductions in yield strength and ultimate strength than tension–compression (T–C) cycles. Meanwhile, under the same axial load condition, the higher the circulating temperature, the more significant the reduction in yield strength and ultimate strength. In essence, this is the result of the coupling effect of low-cycle fatigue and temperature aging. Finally, based on the experimental data, a yield strength prediction model of the P110 casing under the alternating thermal–mechanical coupling condition was established. The research results provide theoretical guidance for the safe design and material selection of a casing string under multistage volumetric fracturing conditions of shale gas exploration.

Current Status of Helium Resource Research and Prediction of Favorable Areas for Helium Reservoir in China

As an unconventional oil and gas reservoir, helium gas reservoirs have gradually become a focus of attention. In recent years, with the continuous increase in demand for helium gas, the uneven distribution of global helium resources has attracted China’s attention to helium resources. In this study, a method for predicting favorable areas of helium gas was proposed based on the natural gas exploration theory and the idea of “finding gas in enrichment areas”. We conducted an in-depth study and analysis of the types of helium gas formations in China by comprehensively using geochemical and isotope-testing data, identifying the distribution of helium source rocks in China. Based on this, we conducted directed analyses of the transport channels and caprock conditions for helium gas, and summarized the enrichment modes of helium gas. Using this method, we predicted five favorable areas for the enrichment of helium gas in China, providing an important basis for the future exploration and development of helium resources in China.

Optimization of tight gas reservoir fracturing parameters via gradient boosting regression modeling

In China, the exploitation of most unconventional oil and gas reservoirs is dependent on hydraulic fracturing, which is a key method employed when developing tight gas formations. Numerous scholars and field engineers, both domestically and internationally, have conducted extensive numerical simulations and physical experiments to study crack propagation and predict post-fracturing productivity in hydraulic fracturing. Although some progress has been reported in this regard, it is difficult to accurately predict the well productivity using mechanistic models owing to the vertical multilayered development of tight gas reservoirs. In this study, vertical fractured wells in a block of Sulige gas field were examined. The block relied on hydraulic fracturing to produce tight gases. However, as development progressed, the available reservoir environment deteriorated, large differences emerged between wells after fracturing, and the fracturing results did not meet the expectations. In this study, geological, construction, and generation data for this block that had been collected since 2007 were analyzed. After applying multiple machine-learning methods to filter outliers and fill in missing values, k-means clustering, classification enhancement, extreme gradient enhancement, and LightGBM algorithms were used to establish a regression model. The analysis results revealed that the regression accuracy of the cluster test set was as high as 70% and that the LightGBM model had the best regression effect among the 227 stripper wells in the block. After optimizing the fracturing construction parameters (fracturing fluid volume, proppant volume, liquid-nitrogen volume, and pumping rate), the average fracturing fluid and liquid-nitrogen volumes per well decreased, whereas the unit reservoir proppant and liquid-nitrogen volumes increased. The results also revealed that 182 wells showed an improved initial production capacity during fracturing. The average gas production index per meter increased by 22.04%. This approach enabled rapid and efficient production forecasting and construction optimization. Moreover, this represents a novel fracture design method that is applicable to onsite engineers in tight gas production fields in the Ordos region.

Geochemical and mineralogical characterizations of Silurian “Hot” shales: Implications for shale gas/oil reservoir potential in Jeffara basin-southeastern Tunisia, North Africa

The Silurian organic-rich hot shale deposits represent the origin of 80–90% Paleozoic sourced hydrocarbons on the entire Saharan Platform. As such, it is an area of significant interest for exploring its potential as an unconventional reservoir and gaining new insights into its properties. In this study, the geochemical and mineralogical analysis of eighty-two borehole samples from three studied wells (T, B, and M) located in Jeffara Basin, in southeastern Tunisa, distributed over a depth between 1200 m and 2200 m, show that the hot shale layer has significant potentials of an unconventional shale gas reservoir. According to the rock-eval and GCMS results, the total organic carbon (TOC) of the hot shale deposits is good to great, ranging between 0.54 wt% and 23.86 wt%, and the average hydrogen index (HI) is around ∼200 mg HC/g of TOC, which indicates that the hot shales were originally rich in type II/III organic matter (OM). The thermal maturity of the preserved OM is determined by the kerogen type with values varying from 0.4% to 1%, and Tmax values reaching 460 °C in T, B, and M wells which indicate that the hot shales preserved early mature to mature OM placed within oil/gas generation window. The calculated geochemical parameters reveal an average hydrocarbon generation potential (HGP) for the three studied wells of 20.37 kg HC/ton rock. In addition, the transformation ratios (TR) in T, B, and M wells are, respectively, 21.12%, 30% and 35.25%. However, only B and M wells show a cross-over layer, with oil saturation index (OSI) exceeding 100%, with significant potential as a hydrocarbon saturated source rock, making it a considerable target for unconventional oil exploration. Relevant results of Rock-Eval, biomarkers and XRD exhibit coherent features that reflect reducing marine conditions during the lower Silurian period. Moreover, the mineralogical composition was investigated to estimate the importance of frackable mineral fractions such as quartz (∼15%) and carbonates (calcite-dolomite). Mineral brittleness index (MBI) was calculated and compared to a well-known unconventional reservoir in the Neal shale member of the Floyd shale group in the Black Warrior Basin (US), which displays moderate to low MBI. The hot shales in the study area have a considerable MBI, which could be easily enhanced by hydraulic fracturing to liberate oil/gas from the potentially saturated unconventional shale reservoir.

Geomechanical analysis of lost circulation control in tight formations

Unconventional oil and gas reservoirs, especially that in tight formations, contribute great parts to the global energy. During drilling in tight formations, lost circulation was one of the major problems, which can cause large amount of non operation time and millions of losses. In order to migrate the problem, lost circulation materials (LCMs) were used to prevent reopening of the fracture by isolating the fracture tip while the calculation of stress intensity factor (SIF) and fracture width is the key to LCMs design. In this paper, a dual porosity medium flow model suitable for tight formation is established to calculate the pressure distribution in fracture, and the fracture width and fracture reopening pressure (FROP) is then calculated by using the semi-analytical fracture mechanics model. Sensitivity analysis of critical parameters, for example, fracture length, wellbore radius, LCMs permeability, viscosity, wellbore pressure, and two rock-mechanics-related properties are implemented. The fracture width is larger in the formation with large horizontal principal stress anisotropy, low Young’s modulus and Poisson’s ratio. The increase in fracture length, wellbore radius and wellbore pressure also contributes to fracture opening. Meanwhile, we compared the situation before and after fracture plugging and the results emphasize that the fracture reopening is less likely to occur under the conditions of high viscosity and low permeability LCMs. The method proposed in this study can be used to calculate fracture width and FROP, which has potential significant application for lost circulation control in tight formation.

Mechanisms by Which an Evaporated Lagoon Sedimentation System Controls Source–Reservoir Preservation in Lei32 Sub-Member Unconventional Oil and Gas

The muddy limestone in the Lei32 sub-member of the Middle Triassic Leikoupo Formation in the well Chongtan 1 (CT1) of the Sichuan Basin has yielded promising industrial oil and gas production. This discovery has the potential to become a significant strategic reservoir in the future for oil and gas exploration in the Sichuan Basin. However, the understanding of hydrocarbon accumulation in the muddy limestone of the Lei32 sub-member remains insufficient, which poses limitations on further exploration selection and deployment strategies. This study focuses on the analysis of core samples and laboratory data in the wells CT1 and Jianyang 1 (JY1), aiming to investigate the source rock and reservoir characteristics of the muddy limestone in the Lei32 sub-member, as well as the primary controlling factors influencing the development of the source rock and reservoir. The results show that the Lei32 sub-member in the Central Sichuan Basin is an evaporated lagoon deposition; the tight argillaceous limestone and limy mudstone exhibit the characteristic of source–reservoir integration, belonging to a new type of unconventional oil and gas reservoir. The reservoir space of the argillaceous limestone and limy mudstone in the Lei32 sub-member primarily consists of inorganic and organic micro–nanopores and microfractures. The average porosity and permeability are 2.7% and 0.19 mD, indicating a low-porosity and low-permeability unconventional reservoir. The clay minerals and gypsum content are the important factors influencing reservoir porosity, and the fractures are key factors influencing permeability. This study will elucidate the specific features of hydrocarbon accumulation in the muddy limestone reservoirs of the Lei32 sub-member and provide insights into its exploration potential.

Research on Fluid–Solid Coupling Mechanism around Openhole Wellbore under Transient Seepage Conditions

Hydraulic fracturing is one of the most important enhanced oil recovery technologies currently used to develop unconventional oil and gas reservoirs. During hydraulic fracture initiation, fluid seeps into the reservoir rocks surrounding the wellbore, inducing rock deformation and changes in the stress field. Analyzing the fluid–solid coupling mechanism around the wellbore is crucial to the construction design of fracturing technologies such as pulse fracturing and supercritical carbon dioxide fracturing. In this study, a new transient fluid–solid coupling model, capable of simulating the pore pressure field and effective stress field around the wellbore, was established based on the Biot consolidation theory combined with the finite difference method. The numerical results are in excellent agreement with the analytical solutions, indicating the reliability of the model and the stability of the computational approach. Using this model, the influence of seepage parameters and reservoir properties on the fluid–solid coupling around the open-hole wellbore was investigated. The simulation results demonstrate that, during wellbore pressurization, significant changes occur in the pore pressure field and effective stress field near the wellbore. The fluid–solid coupling effect around the wellbore returns to its initial state when the distance exceeds four times the radius away from the wellbore. As the fluid viscosity and wellbore pressurization rate decrease, the pore pressure field and effective circumferential stress (ECS) field around the wellbore become stronger. Adjusting the fluid viscosity and wellbore pressurization rate can control the effect of seepage forces on the rock skeleton during wellbore fluid injection. For the same injection conditions, rocks with q higher Young’s modulus and Poisson’s ratio exhibit stronger pore pressure fields and ECS fields near the wellbore. This model furnishes a dependable numerical framework for examining the fluid–solid coupling mechanism surrounding the open-hole wellbore in the initiation phase of hydraulic fractures.

Discovery of Pseudomorph Scapolite and Diagenetic Indication from the Permian Volcaniclastic Rocks in Western Sichuan (SW China)

Volcaniclastic rocks are important unconventional oil and gas reservoirs from which it is difficult to determine the protolith due to strong metasomatic alteration. Intensive alteration has occurred in much of western China, but few robustly documented examples are known from which to assess the alteration processes. Further recognition from the petrological and mineralogical record is essential to quantify the diagenetic environment, the degree of alteration, and its impacts. Permian volcanic rocks are widely developed in the western Sichuan Basin (southwestern China), with a thickness of more than 200 m. The thickness of volcaniclastic rocks in the Permian Emeishan Basalt Formation is up to 140 m, with a 5600~6000 m burial depth. In this study, we demonstrate an approach to recognizing hydrothermal alteration by the occurrence of scapolite megacryst mineral pseudomorphs (SMMPs) in Permian volcaniclastic rocks in the Sichuan Basin (southwestern China). The results show that SMMPs in the Permian volcaniclastic rocks in the western Sichuan Basin mainly occur in the lower part of the Permian basalts as intragranular minerals and rock inclusions. Scapolite is transformed into quartz and albite, and only the pseudomorph is preserved, indicating secondary hydrothermal fluid metasomatic alteration. Scapolite is formed after microcrystalline titanite and is the product of the high-temperature pneumatolytic metasomatism of plagioclase from the mafic protolith during the post-magmatic stage. The mixing of meteoric water and barium-rich hydrothermal fluid leads to the precipitation of barite; additionally, the pores are filled with barite and halite after the alteration of scapolite. The silicification and hydrothermal dissolution of scapolite and the albitization of sodium-rich matrix minerals increase the pore volume, which is conducive to the later recharge by hydrothermal fluids. The discovery of SMMPs can serve as an indicator of the high-temperature pneumatolytic metasomatism and mixing of meteoric water and deep hydrothermal fluid.

Multi-step Fracturing Radial Boreholes for Efficient Development of Unconventional Gas Reservoirs

Multi-step Fracturing Radial Boreholes for Efficient Development of Unconventional Gas Reservoirs

Numerical Simulation of integrated three-dimensional hydraulic fracture propagation and proppant transport in multi-well pad fracturing

Multi-well pad fracturing is an indispensable technology for the sustainable development of unconventional oil and gas reservoirs, but the integrated simulation of fracture propagation and proppant migration in massive fracturing treatments remains challenging, including complicated numerical implementations and computational bottlenecks due to its multi-physics, fracture front propagation, size differences between proppant particles and hydraulic fractures. In this work, an integrated model of fracture propagation and proppant migration in multi-well pad fracturing was established based on the three-dimensional discontinuous displacement method for fracturing deformation computations and the Eulerian-Eulerian framework for capturing proppant concentration. The proposed simulator not only accounts for key physical processes such as stress shadow, dynamic flow rate distribution in the wellbore, fluid leak-off, perforation erosion, fractures evolution, proppant bridging, and gravitational settling, but also couples the simulation of 3D planar propagating fractures and proppant transport at well-pad scale, and presents excellent computational efficiency and promising applications than conventional fracturing models. To explore the fracture geometries and proppant distribution in typically stacked layers, single-well, multi-lateral wells, and multi-well pad fracturing are simulated from simple to complex. The findings showed that fracture propagation is jointly affected by intra-stage, inter-stage, and inter-well stress interference mechanisms, and fracture geometries are characterized by unevenness, asymmetry, and heel bias. Proppant transport is controlled by the fracture width and geometries, and most of the proppant is concentrated near the wellbore area and bridging at the narrow fractures. Fracture geometries and proppant distribution are sensitive to the landing locations of horizontal wells because hydraulic fractures always grow in the path of least resistance. Although close lateral well-spacing is beneficial to improve the stimulation efficiency, there are some challenges such as overlapped SRV, enhanced inter-well interference, and severe fracturing hits. Compared with the layout of stacked wells, staggered wells are not only beneficial to reduce the vertical inter-well interference, but also improve reservoir stimulation efficiency. Overall, the stimulated area of the high in-situ stress layers is relatively low even with intentionally landed wells.

Numerical simulation study on evolution law of three-dimensional fracture network in unconventional reservoirs

It has become a consensus that large-scale hydraulic fracturing is adopted to achieve the stimulation of unconventional oil and gas reservoir. The complex fracture network formed by fracturing is closely related to the effect of reservoir stimulation, which has extremely complicated evolution process. Therefore, it is necessary to study the evolution law of fracture network in large-scale hydraulic fracturing of unconventional reservoirs. In this article, the geological engineering parameters of horizontal well H in shale gas reservoir in southern Sichuan are taken as an example, a three-dimensional fracture network expansion model is established based on the boundary element method and finite volume method, and the simulation of the complex fracture network in a whole well section is carried out to analyze the evolution law of reservoir fracture network under different geological and engineering parameters. The results show that the horizontal stress field distribution has a significant effect on fracture geometric form. Hydraulic fractures in reservoirs with larger horizontal stress difference have stronger directivity, while the horizontal wellbore tends to obtain better reservoir stimulation results when it is parallel to the minimum horizontal principal stress setting. The conjugated natural fracture developed in the reservoir inhibits the hydraulic expansion fractures in both directions. Although it increases the complexity of the fractures, it is not necessarily conducive to improving the reservoir stimulation effectiveness. The lower the strength of natural fracture is, the more complex the fracture geometric form becomes, and the smaller the stimulated reservoir volume is. Correspondingly, the higher the strength of natural fracture is, the simpler the fracture geometric form becomes, and the larger the stimulated reservoir volume is. Suitable fracturing construction displacement can not only contribute to form a more complex fracture distribution, but also help to obtain a larger stimulated reservoir volume. The optimal construction displacement ranges from 10 to 14 m3/min. Low viscosity fracturing fluids are suitable for the formation of long-narrow fractures and able to connect with the remote reservoir and form complex fracture networks. Lower viscosity fluids can be used to achieve better reservoir stimulation effectiveness when sand-carrying capacity is met.

Comprehensive Study on Microscopic Pore Structure and Displacement Mechanism of Tight Sandstone Reservoirs: A Case Study of the Chang 3 Member in the Weibei Oilfield, Ordos Basin, China

With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.

Nanoscale Insights into CO2 Enhanced Shale Gas Recovery in Gas-Water Coexisting Kerogen Nanopores.

The presence of water clusters in kerogen nanopores reduces the occurrence and migration of methane (CH4) and thus affects shale gas extraction. CO2 injection, as an effective approach to enhance shale gas recovery, still presents challenges in its ability to mitigate the impact of immobile water clusters within the kerogen. In this work, molecular dynamics simulations were employed to investigate the microscopic transport process of water clusters and CH4 following CO2 injection in the gas-water coexisting kerogen nanopores. The results demonstrate that CO2 can desorb irreducible water clusters to dredge the pores while extracting CH4, enhancing gas-water mobility, and shale gas recovery by transitioning the wettability of the kerogen nanopore surface from weakly water-wet to CO2-wet. The impact of CO2 on the wettability of kerogen surfaces is primarily manifested in two aspects: CO2 can intrude the interface between water clusters and kerogen to reduce the number of hydrogen bonds between them, resulting in the detachment of water clusters; and the surface of kerogen nanopores can form a layer of CO2 gas film, which prevents desorbed water clusters and CH4 from readsorbing onto the wall surface. This study provides important insights in enhancing the understanding of the microscopic mechanisms in nanoscale flow, as well as for the development of an unconventional gas reservoir.