Reservoir Characteristics and Evolution Mechanisms of the Shale

The quantitative evolution pattern of pore space and genetic pore types along the maturation process in organic-rich shale reservoirs is unclear, which affects the assessment of shale storage capacity and petroleum production. A black shale outcrop sample from Kansas that is of Permian–Pennsylvanian age was collected and subjected to thermal simulation experiments at 10 different maturity stages to understand the pore sizes and pore types. Scanning electron microscopy (SEM) and image processing were used to characterize the full-scale pore-size distribution and volume evolution of this shale sample by combining low-temperature gas (CO₂ and N₂) physisorption and mercury intrusion porosimetry (MIP) in order to discuss the effects of hydrocarbon generation and diagenesis (HG&D) on pore development at different pore sizes. The study showed that the original shale sample is dominated by slit-like pores, with mainly organic matter (OM) pores distributed in 0–100 nm, intraparticle pores (Intra-P) of clays distributed in 30–100 nm, and interparticle pores (Inter-P) distributed in 100–1000 nm. With the increase in maturity or Ro, the OM pores increased gradually, and the OM pore-size distribution diverged to the two poles. In the oil generation stage, the OM pores were distributed in the range of 30–100 nm, while in the gas generation stage, the OM-hosted pores were mainly distributed in the range of 10–20 nm and 100–500 nm. Further into the over-maturity stage, the OM pores were mainly distributed in the range of 0–10 nm and >100 nm. The pore volume distribution across the whole pore sizes showed that the pore volume of low-maturity shale samples was mainly provided by 100–1000 nm (macropores), and the pore volumes of 0–2 nm, 30–100 nm and 1000+ nm pores gradually increase with increasing thermal maturity, with the final pore-size distribution having four peaks at 0–2, 30–100, 500–1000 nm, and 10–100 µm. Hydrocarbon generation mainly affects the pore volume in the 0–2 nm and 100–1000 nm intervals, with a positive correlation. The 2–30 nm and 30–100 nm pores were likely controlled by diagenesis, such as mineral transformation, illitization, and cementation during the maturation process. Full article

Low-temperature nitrogen adsorption is a widely used method for the research and evaluation of gas shale’s pore structure. The existing interpretation method, utilizing gas adsorption isotherms to obtain pore size distribution (PSD), is always based on the one-dimensional geometry model, while the void space of gas shale has strong multi-dimensional characteristics. It is necessary to investigate the nitrogen condensation and evaporation behavior in multidimensional structures. In this study, a series of two-dimensional and three-dimensional models based on ink-bottle pores were constructed. A hybrid molecular simulation approach combining grand canonical Monte Carlo (GCMC) and molecular dynamics (MD) is proposed to simulate the low-temperature nitrogen adsorption isotherms. Three aspects have been analyzed in detail. Compared with the conventional understanding that the threshold of cavitation in the ink-bottle pore only relates to throat diameter, this study discloses a wider and more comprehensive range of conditions of cavitation that considers both the throat length and diameter. As pore spaces of shale samples consist of many complex interconnected pores, the multi-stage ink-bottle pore model is more suitable than the single ink-bottle pore model to similarly reproduce the wider cavitation pressure range. A more universal parameter is proposed that quantitatively unifies the influence of cavity diameter and length on condensation pressure and has good applicability in cavities with different shapes. This work quantitatively studies the nitrogen adsorption isotherms of three-dimensional complex nanopore structures using molecular simulation and provides a reasonable explanation for the low-temperature nitrogen adsorption isotherms of gas shale. Full article

Diagenesis and pore structure are essential factors for reservoir evaluation. marine-continental transitional facies shale is a new shale gas reservoir of concern in the Sichuan Basin. The research on its diagenesis pore evolution model has important guiding significance in its later exploration and development. However, the current research on pore structure changes, diagenesis, and the evolution of marine-continental transitional facies shale is not sufficient and systematic. In order to reveal the internal relationship between pore structure changes and diagenesis, the evolution of marine-continental transitional facies shale was tested by X-ray diffraction, field emission scanning electron microscopy, low-pressure gas adsorption, nuclear magnetic resonance, and the diagenetic evolution sequence and nanopore system evolution of Longtan Formation shale was systematically studied. The results show that the Longtan Formation shale underwent short-term shallow after sedimentation, followed by long-term deep burial. The main diagenetic mechanisms of the Longtan Formation shale include compaction, dissolution, cementation, thermal maturation of organic matter, and transformation of clay minerals, which are generally in the middle-late diagenetic stage. The pore structure undergoes significant changes with increasing maturity, with the pore volumes of both micropores and mesopores reaching their minimum values at Ro = 1.43% and subsequently increasing. The change process of a specific surface area is similar to that of pore volumes. Finally, the diagenetic pore evolution model of Longtan Formation MCFS in Southeastern Sichuan was established. Full article

In contrast to marine shale oil reservoirs, lacustrine shale exhibits rapid lithofacies changes and strong mineral compositional heterogeneity, posing new challenges for the evaluation and distribution prediction of shale oil sweet spots. The oiliness, reservoir properties, oil fluidity, and fracability of different lithofacies were analyzed using emission-scanning electron microscopy (FE-SEM) observation, low-pressure nitrogen physisorption (LNP) analysis, mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), and triaxial compression testing. Based on the mineral composition obtained from X-ray diffraction (XRD) analysis, total organic carbon (TOC) content, and sedimentary structure, four lithofacies were classified, which are organic-rich laminated calcareous shale (LC), organic-rich laminated siliceous shale (LS), organic-rich laminated mixed shale (LM), and organic-poor massive calcareous shale (MC). Considering the factors of oiliness, reservoir properties, oil fluidity, and fracability, the LC and LS lithofacies were determined as being high-quality sweet spots (type I). Within the stratigraphic sequence divided by GR-INPEFA curves, multi-resolution graph-based clustering (MRGC) analysis of sensitive well logs was used to classify the lithofacies, after which the distribution of sweet spots was predicted. The results reveal that the sweet spots exhibit regular changes in their vertical distribution and a ring-like pattern in their planar distribution, influenced by variations in the sedimentary environment. This finding can offer valuable guidance for the future exploitation of shale oil in the Guandong region. Full article

Shale oil and gas, as source-reservoir-type resources, result from organic matter hydrocarbon generation, diagenesis, and nanoscale pore during the evolution processes, which are essential aspects of shale gas enrichment and reservoir formation. To investigate the impact of diagenetic hydrocarbons on shale pore heterogeneity, a thermal simulation of hydrocarbon formation was conducted on immature shale from the Middle Proterozoic Xiamaling Formation in the Zhangjiakou area, covering stages from mature to overmature. Nuclear magnetic resonance (NMR) instruments analyzed the microstructure of the thermally simulated samples, and the multifractal model quantitatively assessed pore development and heterogeneity in the experimental samples. The results reveal that the quartz and clay mineral contents show alternating trends with increasing temperature. Organic matter dissolution intensifies while unstable mineral content decreases, promoting clay mineral content development. Pyrolysis intensity influences Total Organic Carbon (TOC), which reduces as hydrocarbons are generated and released during simulation. Porosity exhibits a decreasing–increasing–decreasing trend during thermal evolution, peaking at high maturity. At maturity, hydrocarbon generation obstructs pore space, resulting in higher levels of bound fluid porosity than those of movable fluid porosity. Conversely, high maturity leads to many organic matter micropores, elevating movable fluid porosity and facilitating seepage. Shale pore heterogeneity significantly increases before 450 °C due to the dissolution of pores and the generation of liquid and gas hydrocarbons. In the highly overmature stage, pore heterogeneity tends to increase slowly, correlated with the generation of numerous micro- and nano-organic matter pores. Full article

Nano-clean fracturing fluids have broad application potential in coalbed methane reservoir fracturing owing to their high stability, good temperature resistance, low filtration loss, and strong frictional resistance reduction. However, the sand-carrying regularity of nano-clean fracturing fluids in coalbed methane reservoirs is unclear, especially for complex fractures with variable directions. This study established a sand transport model that considers proppant collision, wall friction blocking, fracture fluid filtration loss, and the fracture branching angle to study the sand-carrying law of nano-clean fracturing fluids and its influencing factors in complex fractures. The degrees of influence on equilibrium height and placement rate from high to low were the proppant particle size, proppant density, fracturing fluid properties, sand ratio, and pumping discharge volume, and the correlation degrees obtained by grey correlation analysis are 0.862, 0.861, 0.855, 0.854, and 0.832, respectively. As the complexity of the fractures deepens and the resistance increases, the flow rate of the fracturing fluid is reduced, making it difficult for the proppant to enter the branching joints. The sand-carrying performance of a nano-clean fracturing fluid is better than that of a common clear-water fracturing fluid. The fluid-structure coupling model of a nano-clean fracturing fluid can accurately characterize the sand-carrying law of nano-clean fracturing fluids, providing a research basis for optimizing high efficiency sand-carrying fracturing fluid parameters in coalbed methane reservoir fracturing construction. Full article

Organic matter serves as the hydrocarbon-generating parent material for shale reservoirs, in which organic pores are also important reservoir spaces. Different types of organic matter have wide differences in hydrocarbon generation and pore-forming ability. Based on the occurrence state of organic matter, in the over-mature Marine shale organic matter mainly includes in situ and migrated organic matter. It has been extensively studied on in situ organic matter and organic matter migrating into inorganic pores, while there are few reports of organic matter migrating into microfractures. In this study, the over-mature Marine shale reservoir in the first sub-member of the Silurian Longmaxi Formation in the Luzhou area of the Sichuan Basin is taken as an example. Core observation, optical microscope, high-precision large-view scanning (MAPS, modular automated processing system) and mineral analysis scanning (QEMSCAN, quantitative evaluation of minerals by scanning electron microscopy) were conducted to observe the morphological characteristics of organic matter veins, and then analyze the genesis and pore-forming characteristics of such organic matter. The results show that: ① Organic matter veins (OM veins) are soluble organic matter with fractures as an effective channel, and OM veins in the study section is easy to form under the condition of micro-fractures in the shale sweet segment after organic matter generating oil and before gas generation ② Organic matter in the OM veins are less efficient in pore-forming, with sparse pores and smaller pore sizes. The occurrence of fractures varies greatly, including horizontal fractures, oblique fractures and high-angle fractures, which are mostly developed in the Long1₁¹ and Long1₁² layers. ③ The development of OM veins can indicate better reservoir conditions, that is, the layers have strong hydrocarbon generation intensity (strong pore-forming ability of organic matter) and high brittle mineral content (strong reservoir compressibility). The new findings in this paper reveal that OM veins are instructive for the determination of geological–engineering sweet spots in the Longmaxi Formation in the Sichuan Basin, and also provide guidance for future research on occurrence form and geological significance of different types of organic matter. Full article

Shale in the Jurassic Lianggaoshan Formation in central Sichuan exhibits strong heterogeneity. The study of the pore structure characteristics of different lithologies is crucial to the selection of the target interval. Shale samples of the Lianggaoshan Formation from well YS5 in the central part of the Sichuan Basin were analyzed using scanning electron microscopy, low-temperature nitrogen adsorption, high-pressure mercury injection (HPMI), and large -field splicing method -based scanning electron microscopy (LFS-SEM) to elucidate the pore structure characteristics of shale and their influencing factors. The mineral composition of the reservoir in the study area was diverse, primarily consisting of clay minerals, followed by quartz and calcite. The reservoir space comprised intergranular, granular, and organic matter pores, and oil was observed to fill the reservoir space. Reservoir characteristics varied with the lithological properties. In clayey shale, intergranular pores located in clay mineral particles and pores between pyrite and natural fractures were mainly observed, with a bimodal distribution of pore size and peak distribution of 10–50 nm and >100 nm. The storage space of ash-bearing shale mainly consisted of intragranular pores and intergranular (crystalline) micropores, with pore sizes primarily concentrated in the 10–50 nm range. The storage space in silty shale mainly developed in clastic mineral particles such as quartz, followed by clay mineral intergranular pores with a relatively wide distribution of sizes. Pores were mainly inkbottle-shaped and slit-type/plate-type pores, with an average specific surface area of approximately 6.9046 m²·g⁻¹ and an average pore volume of approximately 0.0150 cm³·g⁻¹. The full-pore capillary pressure curve was established using a combination of gas adsorption–desorption tests and HPMI. The fractal dimension of the sample pore structure was calculated, and a significant linear correlation was found between clay mineral content and the fractal dimension. Thus, the pore structure characteristics were mainly controlled by the content and distribution of clay minerals. Full article

The features and formation stages of natural fractures have significant influences on the fracturing of shale reservoirs and the accumulation of oil and gas. The characteristics and evolution of tectonic fractures in the Lianggaoshan Formation in Northeast Sichuan were investigated based on outcrops, drill cores, geochemical data, and acoustic emission test results. Our results demonstrated that the fracture types of the Lianggaoshan Formation were mainly low-degree bedding-slip fractures, followed by high-degree through-strata shear fractures and vertical tensile fractures. The influences of strike-slip faults on the fractures were stronger than those of thrust faults; fractures in thrust faults were concentrated in the hanging wall. The densities of tensile and shear fractures were inversely proportional to the formation thickness, while the density of interlayer slip fractures was independent of the formation thickness. The density of tectonic fractures was proportional to the quartz content. The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), (2) Middle Himalayan tectonic movement (48~32 Ma), (3) Late Himalayan tectonic movement (15 Ma~4 Ma). Fractures greatly improve the oil and gas storage capacity and increase the contents of free and total hydrocarbons. At the same time, they also reduce the breakdown pressure of strata. This study facilitated the prediction of the fracture distribution and oil and gas reservoirs in the Lianggaoshan Formation and provided references for the selection of favourable areas for shale oil and the evaluation of desert sections in the study area. Full article

The Fengcheng Formation of the Mahu Sag is an unconventional reservoir that is of paramount importance for exploration and development of hydrocarbon resource. However, current research on natural fractures in the Fengcheng Formation remains limited, posing challenges for exploration of hydrocarbon resource in the region. This study is based on core observations, thin section identification, geochemical testing and the evolution of regional tectonic movements to investigate the characteristics and periods of formation of natural fractures to address this gap. According to the characteristics of natural fractures in the drilling core samples and microsections, the natural fractures in the Fengcheng Formation can be grouped into structural fractures and atectonic fractures. Structural fractures can be further divided into three subtypes: high-angle interlayer shear fractures, along-layer shear fractures, and tensile fractures. Additionally, non-tectonic fractures in this studied area are primarily bedding fractures, hydraulic fractures, and hydrocarbon-generating overpressure fractures. Vertically, fracture development is more prominent at the bottom of Feng #2 Formation and at the top of Feng #3 Formation. Results also indicate that natural fractures primarily formed during three distinct tectonic movement periods. The initial stage of fracture evolution pertains to the Late Permian period (243–266 Ma), filled with fibrous calcite, and exhibiting a uniform temperature of 70–100 °C. The second stage of fracture evolution occurred during the Late Indosinian to Early Yanshanian period (181–208 Ma), mostly filled or semi-filled with calcite, with a uniform temperature of 110–130 °C. The third stage of fracture development happened during the late Yanshanian to early Himalaya period (50–87 Ma), predominantly filled with calcite, and presenting a uniform temperature of 130–150 °C. Among the various types of structural fractures, the density of high-angle interlayer shear fractures demonstrates a positive correlation with daily gas production, indicating their vital role in promoting hydrocarbon resource production and transportation. Furthermore, microfractures generated by hydrocarbon-generating overpressure fractures exhibit small pore sizes and strong connectivity. These microfractures can create an effective permeability system by connecting previously isolated micropores in shale reservoirs, thus establishing interconnected pore spaces in the shale formation. Full article

The Permian Lucaogou Formation in the Junggar Basin, NW China is the target layer for shale oil exploration, but its hydrocarbon precursors have remained the focus of debate. In this study, we investigated the Lucaogou source rocks throughout Well J10025 by conducting detailed petrological, paleontological, and geochemical analyses for the purpose of revealing the occurrence of cyanobacterial blooms as specific hydrocarbon events in the upper Lucaogou Formation. The morphological characteristics of the microfossils and the geochemical signatures of the microfossil-bearing layers support a biological affinity with Microcystis, a kind of cyanobacteria. Microcystis observed as colonial forms embedded in the upper Lucaogou Formation are of great abundance, indicating the presence of cyanobacterial blooms. They were further evidenced by cyanobacteria-derived biomarkers including low terrestrial/aquatic ratio, high 2α-methylhopane index values, and high abundance of 7- and 8-monomethyl heptadecanes. The blooms occurred in a semiarid and brackish paleoenvironment with anoxic to suboxic water conditions and intermittent volcanic eruptions. Permian Microcystis blooms contributed to the enrichment of organic matter in the upper Lucaogou Formation in two main ways: by directly promoting the accumulation of algal biomass and by creating an oxygen-depleted environment for better preservation of organic matter. This study adds a new record to the geological occurrences of cyanobacterial blooms in the Permian, and provides unique insight into the hydrocarbon generation of Jimsar shale oil in the Junggar Basin. Full article

The organic-rich shales found in the Wufeng–Longmaxi Formation are typically deposited in oxygen-deficient reducing environments. One of the primary sources of debate revolves around the question of whether the anoxic bottom water found in these shales is either euxinic or ferruginous, and this matter remains unresolved. Previous studies have mostly focused on the Wufeng–Longmaxi Formation as a whole in order to understand the key factors that control organic matter accumulation (OMA). However, research on OMA for each member, including the Wufeng Formation (WF), the lower Longmaxi Formation (LLM), and the upper Longmaxi Formation (ULM), has been insufficient. This paper aims to investigate the palaeoenvironmental conditions and OMA mechanisms of the Wufeng–Longmaxi shales in western Hubei by integrating data on total organic carbon (TOC) content, mineral compositions, major and trace elements, and iron speciation. The results indicate that the Wufeng–Longmaxi shales were deposited under highly restricted hydrographic conditions, except for relatively open and upwelling conditions in the upper WF. Silica in the upper WF was primarily biogenic origin and not hydrothermal. Ferruginous conditions were the primary redox conditions for organic-rich shales except for minor formations in the lower LLM that were deposited under euxinic conditions. Due to the tectonic uplift caused by the Kwangsian Orogeny in the upper LLM, the palaeoenvironment was characterized by a warmer and wetter climate, high terrigenous influx, oxic conditions, and low productivity as the result of the insufficient nutrients caused by the weak upwelling, leading to the turnover of graptolite biozones from LM5 to LM6. The factors influencing OMA changed vertically. TOC contents have a highly positive correlation with Al content, indicating that terrigenous influx was the main factor affecting OMA in the WF, which significantly differed from patterns found in other regions. This suggests that the sedimentation rate of organic matter was higher than the terrigenous dilution rate during the WF stage. The combination of redox conditions and productivity were the main factors affecting OMA in the LLM, while terrigenous influx was the key factor controlling OMA in the ULM, resulting in the dilution of organic matter. Regions in the eastern Yiling block, which are close to the Qinling Ocean, show better prospects for shale gas exploration. This research will further facilitate the development of shale gas in this area. Full article

Brittleness is important in the evaluation of the fracturing ability of shale reservoir and has a significant impact on shale gas exploration and development. This paper discusses the characteristics and controlling factors of brittleness of continental shale in the Da’anzhai Member of the Ziliujing Formation of Lower Jurassic age in the northeast Sichuan Basin. Continental shale lithofacies and their associations were grouped into four main rock types: clayey shale, silty shale, shell calcareous clayey shale, and silty clayey shale, characterized by the high clay content and local enrichment of carbonate minerals as a whole. Compared with the marine shale, the continental shale contained a low content of siliceous minerals, a high content of carbonate minerals, and a large number of shell limestone interlayers. Carbonate minerals play an important role in controlling the brittleness of continental shale. The shale interlayers were mainly shell limestone interlayers with a thickness of several centimeters and a large number of shell laminates with thicknesses of several millimeters were also observed. The shell laminates were mainly filled with calcite. Due to the dissolution process, a large number of bedding joints and corrosion joints were formed in the calcite shell layers. In the interlayers with a high shell content, a large number of microfractures developed. The energy consumption required for maintaining fracture expansion was lower after fracturing; the fractures greatly improved the reservoir’s brittleness. Full article

Natural fracture growth plays an important role in shale-oil enrichment. Systematically investigating fracture features and their controlling factors in shale-oil reservoirs is essential for accurately predicting fracture distribution. The controlling factors of fracture distribution in the continental shale of the Qingshankou Formation in the Songliao Basin, China, were systematically analyzed based on the quantitative fracture characterization of outcrops and cores. Strata-confined fractures, throughgoing fractures, bedding-parallel fractures, and stylolites can be observed in the Qingshankou shale reservoir in the study area. Fracture distribution is not only controlled by internal factors, e.g., mineral composition, mechanical stratigraphy, and lithofacies, but also by external factors, e.g., faults and abnormally high pressure readings. Mineral composition is the primary factor governing fracture development, and it not only controls fracture abundance, but it also affects fracture filling and effectiveness. Mechanical stratigraphy determines the spatial morphology and developmental pattern of a fracture. Fractures are well-developed in brittle strata, with fracture spacing being proportional to bed thickness. Lithofacies can determine fracture development by controlling the variation of mineral composition, rock structure, bed thickness, etc. Stress concentration is commonly high at fault tips, intersections, and overlaps, where fracture density is high and has good connectivity. The existence of abnormally high pressure reduces effective stress, promoting shear fracture development. Tensile overpressure fractures can also be generated under small levels of differential stress. Full article