Shallow Shale Research Articles

Pore-Scale Simulation of Deep Shale Gas Flow Considering the Dual-Site Langmuir Adsorption Model Based on the Pore Network Model.

As a key resource in the oil and gas sector, shale gas development profoundly influences the advancement of the global energy industry. Deep shale gas reservoirs, typically found at depths exceeding 3500 m, represent a significant portion of total shale gas reserves. Currently, pore network models primarily simulate middle and shallow shale gas, insufficiently addressing the unique challenges posed by high-temperature and high-pressure conditions in deep shale gas formations. There is an urgent need to explore the microscale flow dynamics of deep shale gas. In this work, we use the pore network model to simulate the flow dynamics of deep shale gas, particularly under nanoconfinement conditions. The simulation integrates adsorption, slip flow, Knudsen diffusion, and bulk flow phenomena. Utilizing the dual-site Langmuir adsorption model tailored for high-temperature and high-pressure conditions enhances the accuracy of gas conductivity calculations for the adsorbed phase, thereby reflecting the specific characteristics of deep shale gas reservoirs. Moreover, this research investigates the flow characteristics of deep shale gas under varying sensitivity parameters, such as water saturation, temperature, and pressure. It explores methane flow dynamics, focusing on effective diffusion coefficients and permeability. The modified approach to calculating adsorption phase conductivity using the dual-site Langmuir adsorption model accurately captures the adsorption behaviors and characteristics of deep shale gas reservoirs.

Drilling Technology of Large Plumb Ratio Shallow Shale Gas Well

Abstract SY1H is the first shallow shale horizontal well deployed in Jilin Oilfield, with a depth of 1,150m in Qing1 section of the target layer, a designed horizontal section length of 2,000m, and a water-drag ratio of nearly 2:1, so the well is characterised by the difficulty of pressurising with a large digit-drag ratio, the high friction between the drilling and the lower casing, and the shale wall being easy to be destabilised and collapsed. There are no horizontal wells in the neighbouring wells with a section of green as the destination layer, and there is a lack of reference materials, and the stability of the shallow shale is not clear. In order to ensure that the well can be reached and drilled for a long time, a technical route was formulated with the objectives of effectively reducing drilling resistance, increasing drilling pressure, and rapid drilling and completion within the collapse cycle, and technical measures such as equipping with a top drive and a high-grade drilling rig to increase the drilling pressure, oil-based drilling fluids and rotary guiding to reduce drilling resistance and the ability to deal with complex situations, and floating casing process to ensure that casing can be smoothly lowered in place, etc., so as to achieve safe and rapid construction of SY1H and achieve a horizontal section of 2,000m. construction and achieve the geological target of 2000m horizontal section.

A Review of Weak Gel Fracturing Fluids for Deep Shale Gas Reservoirs.

Low-viscosity slickwater fracturing fluids are a crucial technology for the commercial development of shallow shale gas. However, in deep shale gas formations with high pressure, a higher sand concentration is required to support fractures. Linear gel fracturing fluids and crosslinked gel fracturing fluids have a strong sand-carrying capacity, but the drag reduction effect is poor, and it needs to be pre-prepared to decrease the fracturing cost. Slick water fracturing fluids have a strong drag reduction effect and low cost, but their sand-carrying capacity is poor and the fracturing fluid sand ratio is low. The research and development of viscous slick water fracturing fluids solves this problem. It can be switched on-line between a low-viscosity slick water fracturing fluid and high-viscosity weak gel fracturing fluid, which significantly reduces the cost of single-well fracturing. A polyacrylamide drag reducer is the core additive of slick water fracturing fluids. By adjusting its concentration, the control of the on-line viscosity of fracturing fluid can be realized, that is, 'low viscosity for drag reduction, high viscosity for sand-carrying'. Therefore, this article introduces the research and application status of a linear gel fracturing fluid, crosslinked gel fracturing fluid, and slick water fracturing fluid for deep shale gas reservoirs, and focuses on the research status of a viscous slick water fracturing fluid and viscosity-controllable polyacrylamide drag reducer, with the aim of providing valuable insights for the research on water-based fracturing fluids in the stimulation of deep shale gas reservoirs.

Multiple hydraulic fracture propagation simulation in deep shale gas reservoir considering thermal effects

Deep and ultra-deep shale gas will gradually become the focus of unconventional oil and gas resources in the petroleum industry. In the development of shallow shale reservoirs, the multi-cluster hydraulic fracturing of horizontal wells is the commonly applied technique to create a network of fractures and achieve reservoir stimulation. However, for deep shale reservoirs, the behavior of multiple hydraulic fracture propagation is affected by stress interference between fractures. On the other hand, it is also influenced by the temperature disturbances caused by the injection of low-temperature fracturing fluids into high-temperature formations and the resulting thermal effects. Currently, most research on multiple hydraulic fracture propagation in shale only considers the interaction between fluids and solids while neglecting thermal effects. Therefore, based on the displacement discontinuity method, finite volume method, and finite difference method, this study established a numerical model for the non-planar propagation of multi-cluster hydraulic fractures in deep shale, considering the thermal effects. And the model was validated through numerical solutions of the temperature field and double-fracture propagation. Moreover, the number of fracture clusters, pumping rate, and formation temperature were selected as influencing factors, and the differences in multiple hydraulic fracture propagation with and without considering thermal effects were analyzed. The results show that as the formation temperature increases, the thermal effects become more significant, leading to greater differences in the morphology of multi-cluster fractures. Moreover, the thermal effects are more significant when the formation temperature exceeds 90 °C. Additionally, appropriately reducing the number of fracture clusters or increasing the pumping rate can to some extent mitigate stress interference between fractures and promote uniform fracture propagation. The findings of this study contribute to understanding the influence of thermal effects on multiple hydraulic fracture propagation and provide theoretical basis for the efficient development of deep shale gas.

Gas-in-place content and occurrence state of deep shale gas in the Luzhou area, Sichuan Basin, China

The exploration and development of deep shale gas has made significant breakthroughs, but due to the characteristics of deep shale gas, there is no recognized and effective method of evaluating gas-bearing. To effectively determine the gas-in-place (GIP) content and occurrence state of deep shale gas, a total of 909 shales were collected for the study utilizing pressure-holding and conventional coring technologies from Wufeng-Longmaxi Formations in the Luzhou area, Sichuan Basin, China. The GIP content of the above shales was evaluated using various methods, including the USBM, polynomial fitting, ACF, MCF, process analysis and carbon isotope fractionation (CIF) methods. The accuracy of the above methods was verified through comparison with the gas content measured by pressure-holding coring. The results demonstrate that (1) the degassing content obtained from conventional coring ranges 0.06–2.13 cm3/g, averaging 0.64 cm3/g; the measured gas content obtained from pressure-holding coring ranges 2.19–11.91 cm3/g, averaging 7.16 cm3/g. The gas content obtained is significantly higher because pressure-holding coring samples have excellent sealing and minimal lost time. (2) The GIP content is underestimated by the USBM method, while the polynomial fitting, ACF, and MCF methods overestimate it. The process analysis and CIF methods can evaluate the GIP content of deep shales more accurately. Based on the comparative results of the adsorbed gas ratio calculated using the process analysis and the CIF methods (33.49% and 24.53%, respectively), it is recommended that the CIF method be given priority when evaluating deep shale gas-bearing. (3) The GIP content of deep shales in the Luzhou area calculated by the CIF method ranges 2.52–11.99 cm3/g, averaging 7.19 cm3/g; the adsorbed gas ratio accounts for 3.41%–53.32%, averaging 24.53%; and the lost gas ratio accounts for 54.01%–97.45%, averaging 86.38%. Compared with medium and shallow shale gas reservoirs in other areas, deep shale gas reservoirs in the Luzhou area have gas-bearing characteristics of high GIP content, low adsorbed gas ratio and high lost gas ratio, which restricts the applicability of traditional evaluation methods.

Accumulation and exploration enlightenment of shallow normal-pressure shale gas in southeastern Sichuan Basin, SW China

Based on the drilling, logging, experimental and testing data of Well PD1, a shallow normal-pressure shale gas well in the Laochangping anticline in southeastern Sichuan Basin, the shallow shale gas reservoirs of the Ordovician Wufeng Formation to Silurian Longmaxi Formation (Wufeng–Longmaxi) were investigated in terms of geological characteristics, occurrence mechanism, and adsorption-desorption characteristics, to reveal the enrichment laws and high-yield mechanism of shallow normal-pressure shale gas in complex structure areas. First, the shallow shale gas reservoirs are similar to the medium–deep shale gas reservoirs in static indicators such as high-quality shale thickness, geochemistry, physical properties and mineral composition, but the former is geologically characterized by low formation pressure coefficient, low gas content, high proportion of adsorbed gas, low in-situ stress, and big difference between principal stresses. Second, shallow shales in the complex structure areas have the gas occurrence characteristics including low total gas content (1.1–4.8 m3/t), high adsorbed gas content (2.5–2.8 m3/t), low sensitive desorption pressure (1.7–2.5 MPa), and good self-sealing. Third, the adsorbed gas enrichment of shales is mainly controlled by organic matter abundance, formation temperature and formation pressure: the higher the organic matter abundance and formation pressure, the lower the formation temperature and the higher the adsorption capacity, which is more beneficial for the adsorbed gas occurrence. Fourth, the shallow normal-pressure shale gas corresponds to low sensitive desorption pressure. The adsorbed gas can be rapidly desorbed and recovered when the flowing pressure is reduced below the sensitive desorption pressure. Fifth, the exploration breakthrough of Well PD1 demonstrates that the shallow complex structure areas with adsorbed gas in dominance can form large-scale shale reservoirs, and confirms the good exploration potential of shallow normal-pressure shale gas in the margin of the Sichuan Basin.

Mineralogical studies of tertiary shales from k-well Akiri field, Niger delta

Shale cuttings from the K-Well (Akiri) in the Niger Delta have been analysed for their mineralogical and geochemical compositions. Analysis of the 2m portion from the 2183, to 3,720m stratigraphic period was performed using X-ray diffraction, inductively coupled plasma optical emission (ICP-OES), and mass spectrometry (ICP-MS). Many types of clay minerals exist, although kaolinite and chlorite predominate. From 3250-3720m in altitude, the illite/smectite composition shifts from a phase with 32% illite layers to a phase with 82% illite layers. Shallow shales had a drop in kaolinite concentration (from 22-16%) whereas deep shales saw a decline (from 29-22%). Unlike chlorite and feldspar, whose abundance do not rise with depth, but quartz does. In all samples, calcite may be found in minute quantities. In this case, the pore water is the source of the potassium. Total organic carbon (TOC) readings obtained from the shale samples demonstrate a high concentration of organic matter in the rock.

Investigation on Nonlinear Behaviors of Seepage in Deep Shale Gas Reservoir with Viscoelasticity

The nonlinear behaviors in deep shale gas seepage are investigated, involving the non-Darcy effect, desorption, and viscoelasticity. The seepage model accounts for the nonlinear compressibility factor and gas viscosity due to their stronger non-linearity at a high pressure and temperature. The viscoelastic behavior in deep shales, including matrix deformation and proppant embedment, is quantified, and the evolution of the time-varying and pressure-dependent porosity and permeability is derived. A semi-analytical approach with explicit iteration schemes is developed to solve the pressure field. The proposed model and method are verified by comparing the simulation results with the field data. The results show that the gas production contributed by the non-Darcy effect and desorption is much higher in deep shale than in shallow shale. However, Darcy flow contributes 85% of the total gas production of deep shales. If the effect of viscoelastic behavior is neglected, the accumulative gas production would be overestimated by 18.2% when the confining pressure is 80 MPa. Due to the higher pressure and temperature, the accumulative gas production in deep shale is 150% higher than that in shallow shale. This investigation helps to clarify the performance of the non-Darcy effect, desorption, and viscoelastic behavior in deep shales, and the proposed model and approach can facilitate the optimization simulations for hydraulic fracturing strategy and production system due to its high efficiency.

Influencing Factors of Drainage and Production and Quantitative Evaluation in Shale Gas Reservoirs

As a transitional energy source, natural gas plays a crucial role in the energy transition. In the efficient development of shale gas, the drainage and production process, as an important link between hydraulic fracturing and production, determines the recovery rate of individual wells. To clarify the main controlling factors of shale gas drainage and production, provide strategies for classification, and improve the recovery rates of individual wells, a numerical simulation method was proposed to analyze the factors affecting drainage and production, and the VIKOR method was used for quantitative evaluation of the drainage and production effects. The research results showed that: (1) The study identified nine main controlling factors affecting drainage and production performance, including gas saturation, permeability, stress difference, burial depth, formation pressure, cumulative fracture volume, final fracture loss rate, average final diversion ability, and wellbore liquid loading. (2) A workflow for quantitatively evaluating the drainage and production effectiveness of shallow shale gas wells and selecting wells with potential for optimized drainage and production was proposed. The correlation between the evaluation results and EUR fitting had an R2 value of 0.71, indicating a good level of credibility. (3) The evaluation results for the target gas field indicated that out of the 16 representative wells, 12 wells have optimization potential, with 5 wells showing significant optimization potential. Studying the rules of shale gas drainage and production and evaluating the drainage and production effects can help us to propose refined drainage and production strategies, which are essential for improving the estimated ultimate recovery (EUR).

Complexity and Heterogeneity Evaluation of Pore Structures in the Deep Marine Shale Reservoirs of the Longmaxi Formation, China

The structural evolution and sedimentary differentiation of the Sichuan Basin in China are complex, with intricate reservoir pore structures that significantly impact shale gas production. This study examines the complexity and heterogeneity of the microscopic pore structures in the deep marine shale reservoir in the Longmaxi Formation. Pore structure characterization techniques are used to compare deep and shallow–medium marine shales, and siliceous and silty shales. The results reveal the factors influencing pore structure and their impact on exploration and development. The key points are as follows: (1) The pore structure of deep siliceous shale is the most complex due to its diverse range of pore development patterns, pore types, and sizes. (2) The box dimension of full pore size is about 1.52 for deep marine shale and 1.46 for shallow–medium shale. Organic matter (OM) content, the degree of pore development, and inorganic mineral content all correlate positively with the complexity of the pore structure in deep marine shale, which affects the formation of high-quality reservoirs. (3) Lateral heterogeneity of pore structures shows strong regional variations in the study area. Heterogeneity is more pronounced in the deep marine shale than in the medium and shallow shale formations. OM mesopores significantly influence the overall heterogeneity of the shale pore system. The deep marine shale reservoir is situated in an area with strong regional variations. The pore structure of high-quality reservoirs is more complex than those of shallow–medium marine shales, displaying notable heterogeneity. Pore structures with fractal dimension values close to that of the shallow–medium formations (box dimensions within 1.5) offer promising targets for the exploration and development of deep marine shale gas.

Impact of Overpressure on the Deep Shale Pore System-A Case Study of Wufeng-Longmaxi Formations from the Southern Sichuan Basin.

This study investigated the effect of overpressure on the deep shale pore system in the Wufeng-Longmaxi Formation (WLF), a well-established shale gas reservoir in the southern Sichuan Basin, China. The Y1 well was drilled to explore deeper overpressured sections of the basin. Organic geochemistry, mineralogy analysis, field emission scanning electron microscopy (FE-SEM), and gas physisorption experiments were conducted to analyze the pore system. Results showed that despite strong compaction, deep organic-rich shale retained large pores. Compared to shallow shale, deep shale had a larger organic porosity with a smaller average pore size, although some pore sizes exceeded those in shallow shale. Nitrogen (N2) adsorption indicated that the abundance of organic matter (OM) affected mesoporous volume and specific surface area (SSA), while carbon dioxide (CO2) adsorption experiments suggested that micropores were not influenced by OM abundance. Comparing calculated pore SSA and volume via gas adsorption of shallower and deep shale samples revealed that, under similar OM abundance, pore SSA was nearly identical, but deep shale had a larger pore volume than shallow shale. The preservation of pores, particularly in deep shale, is attributed to overpressure, which protects against collapse; additionally, generated shale gas during thermal evolution of OM serves as pore support.

Mixed-mode fracture behavior in deep shale reservoirs under different loading rates and temperatures

In the last years, shale gas has gradually substituted oil and coal as the main sources of energy in the world. Compared with shallow shale gas reservoirs, deep shale is characterized by low permeability, low porosity, strong heterogeneity, and strong anisotropy. In the process of multi-cluster fracturing of horizontal wells, the whole deformation process and destruction modes are significantly influenced by loading rates. In this investigation, the servo press was used to carry out semi-circular bend (SCB) mixed-mode fracture experiments in deep shales (130, 160, 190 °C) with prefabricated fractures under different loading rates (0.02, 0.05, 0.1, 0.2 mm/min). The fracture propagation process was monitored using acoustic emission. The deformation characteristics, displacement–load curve, and acoustic emission parameters of shale under different loading rates were studied during the mixed-mode fracture propagation. Our results showed that during the deformation and fracture of the specimen, the acoustic emission energy and charge significantly increased near the stress peak, showing at this point the most intense acoustic emission activity. With the increase in loading rate, the fracture peak load of the deep shale specimen also increased. However, the maximum displacement decreased to different extents. With the increase in temperature, the effective fracture toughness of the deep shale gradually decreased. Also, the maximum displacement decreased. Under different loading rates, the deformation of the prefabricated cracks showed a nonlinear slow growth–linear growth trend. The slope of the linear growth stage increased with the increase in loading rate. In addition, as the loading rate increased, an increase in tension failure and a decrease in shear failure were observed. Moreover, the control chart showing the relationship between tension and the shear failure under different temperatures and loading rates was determined.

Characteristics of Fracturing Fluid Invasion Layer and Its Influence on Gas Production of Shale Gas Reservoirs

With the increase of shale gas resource exploitation in our country during recent decades, the situations of low gas production, fast production decline rate, and low flowback rate have been appearing in field production. It is an urgent problem to be solved in shale gas production and it is therefore necessary to study the interaction of the shale gas reservoir and the detained fracturing fluid. In this paper, the Longmaxi Formation shale samples of Sichuan Basin were selected for a water invasion experiment. The fracture propagation law, the water invasion front location, and the water invasion thickness of deep and shallow shale reservoirs after water invasion were compared and analyzed by CT scanning technology. Based on the analysis of the experimental mechanism, a numerical simulation model was established. The dimensionless permeability and thickness of the fracturing fluid invasion layer were introduced to analyze the positive and negative effects of fracturing fluid retention on the reservoir. The results show that during the hydraulic fracturing of shale gas wells, fracturing fluid can quickly enter the complex fracture network, and then slowly enter the shale matrix under various mechanisms to form the fracturing fluid invasion layer. Compared with shallow shale reservoirs, deep shale reservoirs have lower porosity and permeability, which propagates microfractures in the matrix induced by fracturing fluid retention, and results in a smaller fracturing fluid invasion layer thickness. Both the negative effect of fracturing fluid retention on shale damage and the positive effect of microfracture formation and propagation exist simultaneously. The higher the dimensionless fracturing fluid invasion layer permeability, the more complex the fracture network formed in the fractured reservoir will be, resulting in a longer stable production period and a better development effect. When the dimensionless fracturing fluid invasion layer permeability is greater than 1, that is, when the positive effect of fracturing fluid retention is greater, and the thicker the dimensionless fracturing fluid invasion layer is, the better the development effect will be. Combining reservoir characteristics and fracture development, the key to obtaining high productivity of a shale gas well is to optimize the soaking time and the speed of flowback in order to extend the stable production period. In this paper, the characteristics of the fracturing fluid invasion layer and the influence of fracturing fluid retention on gas well productivity are deeply studied, which provides a certain theoretical basis for the optimization of shale gas extraction technology and the improvement of the gas–water two-phase productivity prediction method for fractured horizontal wells.

Rock Physical Properties of Longmaxi Shale Gas Formation in South Sichuan Province, China

Deep shale gas (burial depth > 3500 m) in the Longmaxi Formation of southern Sichuan Province will be the primary target for exploration and development in China for a relatively long period. However, the lack of a physical basis for the “sweet-spots” seismic and well-logging prediction is caused by uncertainty in the rock physical properties of deep shale gas in the research area. Acoustic and hardness measurements were performed on shale samples from a deep layer of the Longmaxi Formation in southern Sichuan. Microtextural characteristics of the shale samples were also analyzed by conventional optical microscopy and scanning electron microscopy. Based on these measurements, the rock physical properties of the shale samples and control factors are discussed. It is shown that the deep shale samples have similar properties to the shallow shale in mineral composition, microtexture, and pore type. However, the organic pore in deep shale samples is relatively undeveloped, while the dissolved pores are more developed. For high-quality shale samples (total organic content > 2%), crystal quartz of biological origin forms the framework of rock samples, resulting in effective dynamic and static properties, reflecting the elastic behavior of rigid quartz aggregates. For organic-lean samples (total organic content < 2%), orientated detrital clay particles take the role of load-bearing grains. Therefore, these shale samples’ overall rock physical properties are mainly controlled by the elastic properties of “soft” clay. The load-bearing grain variation from organic-rich shale samples to organic-lean samples results in an overturned “V”-type change in terms of velocity versus content. Organic-rich shale samples also show an apparent low Poisson’s ratio. Organic-rich shale has a slight velocity–porosity trend, while organic-lean shale shows a significant velocity–porosity trend. In addition, due to the difference in rock microtexture between organic-rich and organic-lean shale, these two kinds of reservoir rocks can be discriminated in cross plots of P-wave impedance versus Poisson’s ratio and Young’s modulus versus Poisson’s ratio. Change in hardness also reflects the control of microtexture, and shale samples with biological-origin quartz as load-bearing grains show higher hardness and brittleness. However, the variation in quartz content has less of an impact on hardness and brittleness in shale samples with clay as the load-bearing grain. Our results provide an experimental basis for the geophysical identification and prediction of deep shale gas layers.

Self-supporting conductivity in shallow and ultra shallow shale reservoirs: Under hydraulic, CO2 and Sc-CO2 fracturing

To study the differences in self-supporting conductivity among fractures obtained by hydraulic fracturing, CO2 fracturing, and Sc-CO2 (Supercritical carbon dioxide) fracturing, laboratory large-scale fracturing experiments and conductivity tests were carried out. To simulate the reservoir conditions as realistically as possible, the rock slabs used in the conductivity tests were all cut from the samples after fracturing experiments. Before a conductivity test, the fracture surfaces of each rock slab were digitized by laser scanning and 3D reconstruction technology. The JRC of each rock slab is calculated by using the point cloud data. Then, the self-supporting conductivity of each rock slab was tested under different conditions, and a relationship between the JRC, closure stress and sliding displacement and the self-supporting conductivity of fractures obtained by different fracturing techniques was analyzed. The experimental results show that: The JRC of the fractures obtained by Sc-CO2 fracturing is higher than that of CO2 fracturing. Moreover, the JRC of fractures in hydraulic fracturing is the lowest among the three fracturing technologies. The self-supporting conductivity of the fractures has a positive correlation with their JRC value. Compared to hydraulic fracturing and CO2 fracturing, the fractures obtained by Sc-CO2 fracturing have significant advantages in self-supporting conductivity regardless of slip displacement and closure stress.

Characterization of multi-scale pore structure and analysis of adsorption capacity influencing factors in Zhaotong shallow shale gas reservoir

Characterization of multi-scale pore structure and analysis of adsorption capacity influencing factors in Zhaotong shallow shale gas reservoir

Adsorption behavior and mechanism analysis of siloxane thickener for CO2 fracturing fluid on shallow shale soil

Reducing the adsorption of CO2 thickeners in soil particles of shallow shale is a pathway to protect the shale environment and water cycle. In this work, we first synthesized a siloxane-based thickener named AOB based on ring-opening polymerization and hydrosilylation reaction and discussed the influence of geological factors (including contents, pressure, temperature and shear rate) on the adsorption capacity of this thickener. The soil surface adsorption behavior of AOB was characterized by a self-assembled high-pressure soil adsorption device and the adsorption capacity was analyzed by Attenuated Total Reflectance Infrared Spectroscopy (ATR-FTIR). The results showed that AOB molecule belongs to the monolayer adsorption type on the soil surface by measuring the contents. Moreover, an inverse relationship was showed between pressure and adsorption capacity for AOB, while the significantly proportional relationship was presented for temperature and shear rate, respectively. It is found that the combined force formed by soil repulsion (originated from aromatic groups in AOB) and grid drag weakens the adsorption of AOB on the soil surface, resulting in a much lower adsorption capacity than the commercial PDMS. This work not only paves a new avenue for synthesizing siloxane-based polymer as CO2 thickener, but also provides an efficient measure to reduce the adsorption of thickener on the shallow soil.

Exploration and development in the Zhaotong national shale gas demonstration area: Progress and prospects

The Zhaotong national shale gas demonstration area in Yunnan (hereinafter referred to as demonstration area) is China's third largest national shale gas production base after Changning–Weiyuan in Sichuan and Fuling in Chongqing. And after more than ten years of deep and careful cultivation, a series of important achievements have been obtained in the exploration and development. From the perspective of exploration and development history, theory and technology, this paper systematically summarizes the exploration discovery process and productivity construction progress of shale gas in the demonstration area, expounds the geological exploration theories and key technologies of mountain shale gas, and predicts their development prospect and direction. And the following research results are obtained. First, the exploration and development in the demonstration area has gone through five development stages, and so far, three major productivity construction zones have been formed, including Huangjinba and Zijinba middle–deep shale gas zones and Taiyang shallow shale gas zone, with cumulative proved geological reserves more than 3100 × 108 m3 and cumulative gas production more than 72 × 108 m3. It has been constructed into the third largest green shale gas demonstration base in China. Second, the “multi-field coordination and multi-element coupling” mountain shale gas enrichment, accumulation and occurrence theory of “sedimentary background controlling source rock and reservoir, reworking intensity controlling preservation, and three-dimensional sealing controlling enrichment” is put forward innovatively, and the “three-dimensional sealing system” accumulation model of extrabasinal shallow shale gas is established. Third, a series of zone selection and evaluation technologies for mountain shale gas in strongly reworked complex structural areas have been developed, and the concept of geology–engineering integration has first been adopted to create transparent shale gas reservoirs and cultivate high-yield wells. A major exploration breakthrough has been achieved from marginal basin medium deep shale gas layers to extrabasin ultra shallow to medium shallow ones, and domestic first large-scale monoblock shallow shale gas field with reserves over 2570 × 108 m3 has been discovered. Fourth, a landmark technological achievement and efficient development model with geology–engineering integration and shale geomechanical evaluation as the core has been formed, which leads the clean, green and efficient exploration and development of mountain shale gas. In conclusion, it is necessary to implement the exploration strategic idea of “two outgoing” in the demonstration area, i.e., “walking out of the stable area of the basin and marching into the complex structure areas in the Dianqianbei Depression” and “walking out of the Wufeng–Longmaxi Formation and exploring other layers for breakthrough”. What's more, it is recommended to carry out the double-layer stereoscopic horizontal well pattern deployment of “Leping Formation CBM (coal measure gas) + Longmaxi Formation shale gas” appropriately in a large scale, so as to establish a new integrated development model for the three-dimensional efficient development of mountain shale gas and CBM.

Statistical Analysis of Controlling Factors on Enhanced Gas Recovery by CO2 Injection in Shale Gas Reservoirs

Development of shale gas reservoirs is the fastest growing area on a large scale globally due to their potential reserves. CO2 has a great affinity to be adsorbed on shale organic surface over CH4. Therefore, CO2 injection into shale reservoirs initiates a potential for enhanced gas recovery and CO2 geological sequestration. The efficiency of CO2 enhanced gas recovery (CO2-EGR) is mainly dominated by several shale properties and engineering design parameters. However, due to the heterogeneity of shale reservoirs and the complexity of modeling the CO2–CH4 displacement process, there are still uncertainties in determining the main factors that control CO2 sequestration and enhanced CH4 recovery in shale reservoirs. Therefore, in view of the previous sensitivity analysis studies, no quantitative framework, accurate CO2-EGR modeling, or design process has been identified. Thus, this work aimed to provide a practical screening tool to manage and predict the efficiency of enhanced gas recovery and CO2 sequestration in shale reservoirs. To meet our objectives, we performed correlation analysis to identify the strength of the relationship between the examined shale properties and engineering design parameters and the efficiency of CO2-EGR. Data for this study was gathered across publications on a wide subset of numerical modeling studies and experimental investigations. The sensitivity of data was further improved by a hybrid approach adopted for handling the missing values to avoid bias in our data set. Our results indicate that CO2 flooding might be the best applicable option for CO2 injection in shale reservoirs, whereas the huff-and-puff scenario does not seem to be a viable option. The efficiency of CO2-EGR increases as the pressure difference between injection pressure and reservoir pressure increases. The results show that shallow shale reservoirs with high fracture permeability, total organic content, and CO2–CH4 preferential adsorption capacity are favorable targets for CO2-EGR. Moreover, our results indicate that a successful hydraulic-fracture network with effective values of fracture permeability and conductivity is essential for a higher CO2-EGR efficiency. Well spacing and fracture half-length are crucial engineering features in CO2-EGR process design that must be carefully optimized due to their negative effect on CH4 production and positive effect on CO2 storage. Our statistical analysis lays a foundation for efficient CO2-EGR design and implementation and presents an important contribution to the field of reaching the target of net-zero CO2 emissions for energy transitions.

Gas-Bearing Property in Deep Marine Shale and Its Micro Controlling Factors: Evidence from the Lower Silurian Longmaxi Formation in Southern Sichuan, China

Abstract The gas content in shale reservoirs is often determined by the micro storage and sealing capacities of the reservoir. Deep shale reservoirs are in the high- or over-thermale maturity stage and have complex pore structure and connectivity, which are highly heterogeneous in vertical distribution. Research on the gas-bearing property of deep shale reservoirs is limited by these complex microscopic conditions. To analyze the gas-bearing characteristics of deep shale reservoirs, this work collected and summarized data on total organic carbon content, mineral composition, porosity, water saturation, and gas content measured on-site for the Longmaxi Formation in the Sichuan Basin in southern Sichuan, China. Then, experimental methods, such as X-ray photoelectron spectroscopy, transmission electron microscope, low-pressure N2 adsorption, spontaneous imbibition, and high-pressure methane adsorption, were used to analyze the micro storage and sealing capacities of the deep shale reservoirs. The results show that, different from shallow shale reservoirs (<3500 m), deep shale reservoirs have a higher graphitization degree and water saturation. An abundance of graphite structures often leads to weak resistance of organic matter to compression, deformation, or even collapse of pores in organic matter and severe damage to the gas storage space. However, a higher degree of graphitization can enhance the ability of the shale reservoirs to adsorb gas and self-sealing. The high water saturation in the reservoirs can interact with clay minerals and negatively affect the gas accumulation, storage, and transmission capacities of the shale reservoirs. However, the upper shale reservoirs with higher water saturation can seal the lower shale reservoirs, helping it preserve shale gas. Based on the vertical distribution of graphite structure, clay minerals contents, lithofacies, and water content in deep shale reservoirs, the essential microscopic conditions for deep shale reservoirs to have high gas content were proposed. This paper provides a detailed explanation and evaluation of deep shale’s storage and sealing capacities at the microscopic scale and can serve as a reference for further identifying the patterns for high-yield and rich shale gas reservoirs and improving deep shale gas exploration technologies.