Shale Evolution Research Articles

Thermal behavior of minerals in shale and its influence on evolution of gas-flow channels under thermal shock

Thermal shock-induced damage can significantly enhance the connectivity of the rock's fracture network. Thermal Enhanced Recovery (TER) technology holds promising potential for application in shale gas production. Nevertheless, there is still a lack of direct experimental studies focusing on the evolution of shale's gas-flow channels and the mechanism of thermal fracturing in shale under the influence of thermal shock. In this study, we initially investigated the impact of thermal shock on various minerals in shale through X-ray diffraction (XRD) analysis and scanning electron microscope (SEM) imaging, and examined the mass and heat variation with temperature using Thermogravimetry-Differential Scanning Calorimetry (TG-DSC) testing. Subsequently, we assessed the alterations in shale's internal structure due to thermal shock through low-temperature gas (N2) adsorption (LTGA) analysis, and observed the distribution and expansion patterns of shale fractures under thermal shock using computed tomography (CT). Finally, we evaluated the changes in shale permeability before and after thermal shock. The findings indicate that quartz, feldspar, and clay exhibit relatively stable behavior in shale under thermal shock, whereas carbonate and pyrite are prone to crack. Under the combined influence of mineral cracking and thermal stress, the internal pore structure of shale tends to enlarge in size while reducing in surface area. The substantial decrease in pore specific surface area highlights the considerable reduction in gas adsorption capacity. Furthermore, fractures expand along the bedding planes as surface fractures. The expansion of pores and fractures promotes the formation of primary gas-flow channels. In addition, the aforementioned test results demonstrate a high level of consistency, specifically highlighting a distinct threshold temperature (500 °C) for the alteration of various physical parameters of shale during thermal shock. This study is anticipated to offer insights into the implementation of TER technology in the oil and gas industry.

Mechanical responses and failure characteristics of longmaxi formation shale under real-time high temperature and high-stress coupling

For the safe and effective extraction of deep shale gas, it is essential to analyze the mechanical responses and failure characteristics of shale under real-time high temperature and high-stress coupling. Herein, triaxial compression experiments on Longmaxi Formation shale were carried out with various bedding angles under different confining pressures and real-time temperatures. The experimental results demonstrate that high confining pressure can transform the mechanical performance of shale from brittle to plasticity. Real-time high temperatures not only can aggravate this transition process but also cause discontinuous micro-rupture before shale failure. The acoustic emission (AE) evolution of shale under various confining pressures and real-time temperatures is generally similar and can correspond with the division of stress-strain stages. However, changes in confining pressure and real-time temperature have opposite effects on AE activity rate and associated parameters. In the deep environment, the real-time high temperature can also drive additional pores and microcracks, which change the microstructure of shale samples. Under high confining pressure, the impact of real-time high temperature on macroscopic failure modes diminishes, resulting in shale samples typically exhibiting the single shear failure mode. Furthermore, high confining pressure and real-time high temperature have different micro-mechanisms for improving shale ductility, as evidenced by their distinct effects on AE evolution.

New insights into the role of system sealing capacity in shale evolution under conditions analogous to geology: Implications for nanopore evolution

Closed and semi-closed pyrolysis of a lacustrine shale sample was conducted using the same instrument characterized by lithostatic pressure and limited reactive space in order to unravel the impacts of the system sealing capacity on organic matter occurrence and nanopore development in shales under conditions analogous to natural processes. The solid residues were subjected to organic geochemical measurements, low-pressure gas (N2 and CO2) adsorption tests, and field emission-scatter electrical microscope analysis. The results revealed that solvent extraction played positive and negative roles in the pore development of solid residues from both systems at different thermal maturities. Inorganic and organic pores were primarily filled or shielded by soluble bitumen at low and high temperatures, respectively. The occurrences of organic matter in solid residues from the two systems were different at lower temperatures but gradually evolved similarly at higher temperatures and were dominated by nanoscale interparticle organic matter. Organic pore occurrence in solid residues from the two systems was approximately comparable. However, differences in pore volume and specific surface area of solid residues from the closed and semi-closed systems increased measurably below 550 °C. At 550 °C, a strong mechanical compaction and overpressure environment caused deformation and closure of pores surrounding rigid minerals and pores associated with ductile minerals surrounding organic matter in solid residue from the closed system, while only a few pores surrounding rigid minerals from the semi-closed system deformed. Consequently, similar pore parameters of solid residues from the two systems were obtained at this temperature. Additionally, the variation in organic porosity of solid residues from the two systems has obvious stages based on mass balance calculation. The organic porosity evolution is collectively affected by system sealing capacity and thermal maturity at lower matured stages. In contrast, organic porosity evolution in solid residues is independent of system sealing capacity at high- and overmatured stages. Although the depositional environment is different, this study provides direct evidence that the difference in system sealing capacity is not the predominant factor leading to different organic pore developments in the Silurian and Cambrian shales in South China.

Triaxial Deformation of the Goldwyer Gas Shale at In Situ Stress Conditions—Part I: Anisotropy of Elastic and Mechanical Properties

The evolution of shale’s mechanical properties with confining pressure, temperature, and mineral composition directly influences fracture closure besides the effect of in situ stress variation across lithologies. We are the first to perform experimental study to characterize the mechanical properties of the Goldwyer gas shale formation located in the Canning Basin, Western Australia. We have performed constant strain rate multistage triaxial tests at in situ stress condition (confining pressure ≤ 22 MPa) on 15 samples of the Goldwyer gas shales with variable minerology, organic content, and heterogeneity. Deformation tests were conducted at room temperature and in drained conditions on cylindrical samples cored parallel (horizontal) and perpendicular (vertical) to the bedding plane. Both triaxial compressive strength (σTCS) and static young’s modulus E show a strong sensitivity to confining pressure and mineralogy, while only E shows a directional dependency, i.e., Eh > Ev. The internal friction coefficient µi in a plane parallel to the bedding is 0.72 ± 0.12, while it is only 0.58 ± 0.17 in the orthogonal direction. Both σTCS and E are significantly lower when larger fractions of weak mineral constituents are present (clays or organic matter). We observe that the Young’s modulus of most vertical samples is best approximated by Reuss’s bound, whereas that of horizontal samples is best approximated by Hill’s average of Voigt and Reuss bounds. The most prospective G-III unit of the Goldwyer shale formation (depth > 1510 m) is semi-brittle to brittle, making it suitable for future development.

Thermal maturity: The controlling factor of wettability, pore structure, and oil content in the lacustrine Qingshankou shale, Songliao Basin

Shale oil resources are abundant in the Qingshankou Formation of the Songliao Basin, but there are significant production differences between wells. Although there are many factors affecting shale oil production capacity, they are all fundamentally reflected in the differences of pore structure and oil-bearing; however, research on the pore structure and oil-bearing characteristics of naturally mature shale is still rarely reported. Lacustrine shales with low to high maturity developed in the Qingshankou Formation, Songliao Basin; these shales can be used as good natural mature samples to reveal the wettability, pore structure, oil content, and evolution of shale under the control of thermal maturity. In this study, geochemistry, oil content, and mineral composition information were analyzed using total organic carbon, thermal maturity, Rock-Eval pyrolysis, and X-ray diffraction; low-temperature nitrogen adsorption–desorption (N2GA), nuclear magnetic resonance (NMR), high-pressure mercury injection, and field emission scanning electron microscopy (FE-SEM) were used to analyze the shale pore structure; and spontaneous imbibition (SI) combined with NMR and contact angle measurement (CAM) experiments were performed to reveal the shale wettability. The results indicate that with the evolution of maturity from low to high, the cracking degree of organic matter (OM) and the amount of hydrocarbon generation increases, and the scale (number, size) of OM pore development continues to increase. The porosity, pore volume, and Brunauer–Emmet–Teller specific surface area of shale increased continuously due to the increased thermal evolution of OM, and a great many of micropores formed in the shale. Therefore, the average pore size decreased with increased maturity. In addition, shale oil content also improves with the continuous hydrocarbon generation of OM in the process of thermal evolution; The wettability of the shale interior and surfaces gradually changes from water wetting to oil wetting when vitrinite reflectivity (Ro) > ∼1.20% and the degree of oil wetting continues to increase as maturity increases. The crude oil generated by kerogen continues to flow from micropores to macropores, and the pore network continues to develop with increasing oil wetting degree, which is beneficial to crude oil migration and accumulation in the shale reservoir.

New insights into the role of system sealing capacity in shale evolution under conditions analogous to geology: Implications for organic matter evolution and petroleum generation

Closed and semi-closed pyrolysis of a lacustrine shale sample were conducted using the same instrument characterized by lithostatic pressure and limited reactive space in order to unravel the impacts of system sealing capacity on organic matter evolution and hydrocarbon generation in shales under conditions analogous to natural processes. The products and solid residues were subjected to chemical composition determination, gaseous carbon isotopic composition analysis, solvent extraction, and Rock-Eval pyrolysis. Higher organic matter transformation and oil retention contents were obtained at 300–500 °C in the closed pyrolysis system compared to those in the semi-closed system at the same temperature ranges. However, lower yields of hydrocarbons except for methane were obtained in the closed system at this temperature range, while the iso-/n-C4,5 as well as C1/C1-5 values were significantly higher in this system. Stronger recombined reactions between kerogen and hydrocarbons were proposed to occur at 300–500 °C during the closed pyrolysis process, leading to the consumption of oil and hydrocarbon gases. Ultimately, positive deviations of initially more negative δ13C2∼3 values were occurred in the closed system, resulting in similar δ13C2∼3 values from the two systems before secondary cracking of hydrocarbon gases commences, but the δ13C1 value from the closed system was overall more negative. Different water retention ratios and hydrocarbon expulsion efficiencies induced by system sealing capacity are the predominant factor controlling organic matter evolution and petroleum generation during the pyrolysis processes. This highlights that the different gas contents of the Cambrian and Silurian shales in South China may be associated with the differences in the system sealing capacities of shales, although the sedimentary environment of the studied sample is lacustrine, and the lower methane content of the Cambrian shale gas is probably ascribed to semi-closed system. Finally, a higher ratio of oil cracking gas may be an important signal for natural gas systems that have better exploration potential.

Novel method for determining the oil moveable threshold and an innovative model for evaluating the oil content in shales

In unconventional resource exploitation, an accurate evaluation of the oil content in shale is essential for locating favorable exploration zones. However, the substantial heterogeneity in shales has caused significant uncertainty in exploration. The commonly applied oil content evaluation model uses a single oil movable threshold (OMT) as a constraint. However, the OMT value is not unique in shale evolution. In this research, the parameter Tmax representing the thermal maturity of the source rock is introduced as a variable to construct an innovative three-dimensional model for oil content evaluation. The source rock of the Paleogene Shahejie Formation in the Bohai Bay Basin was selected as an example to demonstrate the application. With an initial value of 84.1 mg HC/g TOC, the OMT decreased with increasing Tmax, eventually reaching 51.2 mg HC/g TOC. The proportions of enriched, moderately enriched, less efficient, and invalid resources were 31.6%, 6.6%, 47.4%, and 14.5%, respectively. Our new model is advantageous because it evaluates the shale oil quality in terms of geochemistry and oil movability within the context of thermal maturity. Our research can offer a more accurate model and workflow for shale oil evaluation to can reduce the potential exploration risk.

Study on the Damage Evolution Process and Fractal of Quartz-Filled Shale under Thermal-Mechanical Coupling

Filling of brittle minerals such as quartz is one of the main factors affecting the initiation and propagation of reservoir fractures in shale fracturing, in order to explore the failure mode and thermal damage characteristics of quartz-filled shale under thermal-mechanical coupling. Combining the theory of damage mechanics and thermoelasticity, RFPA2D-Thermal is used to establish a numerical model that can reflect the damage evolution of shale under thermal-solid coupling, and the compression test under thermal-mechanical coupling is performed. The test results show that during the temperature loading process, there is a temperature critical value between 60°C and 75°C. When the temperature is less than the critical temperature, the test piece unit does not appear obvious damage. When the temperature is greater than the critical temperature, the specimen unit will experience obvious thermal damage, and the higher the temperature, the more serious the cracking. Under the thermal-mechanical coupling of shale, the tensile strength and elastic modulus of shale show a decreasing trend with the increase of temperature. The failure modes of shale under thermal-solid coupling can be roughly divided into three categories: “V”-shaped failure (30°C, 45°C, and 75°C), “M”-shaped failure (60°C), and inverted “λ”-shaped failure (90°C). The larger the fractal dimension, the more complex the failure mode of the specimen. The maximum fractal dimension is 1.262 when the temperature is 60°C, and the corresponding failure mode is the most complex “M” shape. The fractal dimension is between 1.071 and 1.189, and the corresponding failure mode is “V” shape. The fractal dimension is 1.231, and the corresponding failure mode is inverted “λ” shape.

Porosity model and pore evolution of transitional shales: an example from the Southern North China Basin

The evolution of shale reservoirs is mainly related to two functions: mechanical compaction controlled by ground stress and chemical compaction controlled by thermal effect. Thermal simulation experiments were conducted to simulate the chemical compaction of marine-continental transitional shale, and X-ray diffraction (XRD), CO2 adsorption, N2 adsorption and high-pressure mercury injection (MIP) were then used to characterize shale diagenesis and porosity. Moreover, simulations of mechanical compaction adhering to mathematical models were performed, and a shale compaction model was proposed considering clay content and kaolinite proportions. The advantage of this model is that the change in shale compressibility, which is caused by the transformation of clay minerals during thermal evolution, may be considered. The combination of the thermal simulation and compaction model may depict the interactions between chemical and mechanical compaction. Such interactions may then express the pore evolution of shale in actual conditions of formation. Accordingly, the obtained results demonstrated that shales having low kaolinite possess higher porosity at the same burial depth and clay mineral content, proving that other clay minerals such as illite–smectite mixed layers (I/S) and illite are conducive to the development of pores. Shales possessing a high clay mineral content have a higher porosity in shallow layers (< 3500 m) and a lower porosity in deep layers (> 3500 m). Both the amount and location of the increase in porosity differ at different geothermal gradients. High geothermal gradients favor the preservation of high porosity in shale at an appropriate Ro. The pore evolution of the marine-continental transitional shale is divided into five stages. Stage 2 possesses an Ro of 1.0%–1.6% and has high porosity along with a high specific surface area. Stage 3 has an Ro of 1.6%–2.0% and contains a higher porosity with a low specific surface area. Finally, Stage 4 has an Ro of 2.0%–2.9% with a low porosity and high specific surface area.

Anisotropic characteristics of crack initiation and crack damage thresholds for shale

The inherent anisotropy is the most important structural feature of shale. Most research on the mechanical behavior of shale has focused on its anisotropic strength, deformation and failure patterns. Few studies have examined the anisotropic micro-failure mechanism and failure process of shale. To investigate the anisotropic crack initiation mechanism and evolution of shale during the progressive rock failure process, two stress thresholds (i.e., crack initiation stress (σci) and crack damage stress (σcd)) and two strain thresholds (i.e., crack initiation strain and crack damage strain) of shale under various bedding layer orientations and confining pressures are identified on the basis of the crack volumetric strain. The anisotropic characteristics of the four thresholds are described. The crack initiation stress can be seen as independent of the bedding layer orientation, but the other thresholds are strongly dependent on the bedding layer inclined angle. The physical mechanism of this phenomenon is analyzed in detail. The anisotropic features of the mutual relationships among the peak stress (σc), σci and σcd are presented. The ratios σci/σc and σci/σcd at confining pressures greater than 30 MPa and the ratio σcd/σc increase first and then decrease with the increasing inclination angle. A high confining pressure constraints shale from entering the unstable crack propagation stage but has little effect on preventing crack propagation once it has entered this stage. The anisotropic characteristics of these thresholds can provide meaningful information for understanding the anisotropic deformation and failure mechanism of shale.

The Controlling Effects of Compositions on Nanopore Structure of Over-Mature Shale from the Longtan Formation in the Laochang Area, Eastern Yunnan, China

Over-mature shale has undergone complex geological processes, e.g., diagenesis, deep thermolysis, epigenesis, and metamorphism. During this series of processes, the internal components of shale are transformed coordinatively, and the special pore structure with a complex genesis in the over-mature shale is formed. The study of the special pore structure of over-mature shale and its main controlling factors can provide theoretical support for shale gas exploration and development. In this study, the over-mature shale of the Longtan Formation in the Laochang area, eastern Yunnan Province, China, was tested and analyzed to determine the total organic carbon content, kerogen microscopic composition, and its vitrinite reflectance. Moreover, the mineral composition and pore characteristics of the shale were tested using X-ray diffraction, the argon ion polishing field emission scanning electron microscopy technique, and the low temperature nitrogen adsorption experiment. The results show that the compositions of Longtan Formation shales have a low rigid clastic particles content, high clay content, and abundant metasomatic ankerite, and that the organic matter, dominated by type III, is highly mature. At the same time, the shale pore structure is characterized by a large average pore size, well-developed macropores, and a high number of micropores and mesopores. By analyzing the transformation of the mineral composition of shale during thermal evolution, the controlling factors of pore structure are determined. During the evolution of shale, the intergranular pores (mainly large pores) between rigid minerals are destroyed in large quantities. After a short period, a large number of dissolved pores with the pore size of macropores are formed in the acid-resistant minerals under the action of organic acid. These dissolved pores, together with the remaining intergranular pores of rigid minerals and micro-fractures, form most of the macropores of shale. There is a large amount of ankerite in over-mature shale formed during metasomatism, which occludes some pores of shale. However, intragranular pores and cleavage-sheets develop in ankerite, contributing some porosity to the shale reservoir. Inter-clay pores and organic matter pores constitute most shale micro and mesopores, and between which inter-clay pores take dominance.

Characterization of hydrocarbon/pores generation and methane adsorption in shale organic matter

ABSTRACTThe exploration and development of shale gas reservoirs has been of growing interest in the industry in recent years. It has been widely acknowledged that, during different thermal evolution stages, some characteristics including: the hydrocarbon-generation mechanism, development of organic matter pores, and methane storage/transport mechanism in organic matter/pores will affect shale gas desorption and production fundamentally. However, current research has failed to reveal them completely, which introduces large discrepancies between actual and predicted production in some shale gas reservoirs. In this paper, for the four thermal evolution stages of shale organic matter, i.e., the biochemical, thermo-catalytic, thermo-cracking and deep high temperature phases, respectively, characteristics of products generated from shale kerogen, including the form and quality of the solid frame, gas-oil ratios, and pore characteristics in organic matter (e.g., types of pores, pore wall materials) were first investigated. A new classification method for organic-matter pores was proposed. Additionally, methane absorption characteristics in shale organic matter and pores were demonstrated, the fact that water is involved during each thermal evolution phase was addressed, and current theories of solid-gas interface adsorption/desorption in the organic matter in shale were questioned. This work concluded that the system of solid-gas interface differs from actual shale reservoirs, so predicting production based on this understanding leads to significant inaccuracies. This work explained the possibility of solid-liquid interface effects in the organic matter of shale through analyzing product-generation and pore-formation mechanisms during the evolution of shale, which will directly affect potential reserves of shale. Therefore, this work should provide a basis for improving the accuracy of production predictions in actual reservoirs and should assist analysts in determining reasonable shale gas targets.

Reversal of Basement-Block Motions in Cambay Basin, India, and its Importance in Petroleum Exploration

The study of the nature of the basement and the reversals of the sense of movements along basement fault blocks are of great significance to petroleum exploration in the Cambay graben basin of western India. Oil accumulation in the basin is controlled primarily by basement relief and fault-block tectonics. The Cambay basin is a composite basin characterized by a two-stage structure. The Precambrian basement of the basin, composed of igneous and metamorphic rocks, is an extension of the Aravalli-Delhi, Satpura, and Dharwar orogenic belts trending, respectively, northeast-southwest, east-northeast-west-southwest, and north-south. The present basin apparently first began to form during the Mesozoic (Jurassic) when the region was an undisturbed shelf bounded on the east by the Indian shield. An intracratonic graben came into existence on this shelf during or immediately following the formation of the latest Cretaceous Deccan traps. A thick sequence of Tertiary sediments was deposited directly above the trap. During Paleocene-early Eocene time, the Olpad Formation was deposited on a Deccan t ap floor characterized by narrow fault blocks--horsts and grabens. Some of these fault blocks reversed their structural relations during the deposition of the early Eocene Cambay Shale. Such a reversal is exemplified by (1) the north-south Sanand-Nawagam-Dholka block, parallel with the Dharwar strike and (2) the east-northeast-striking Kosamba-Olpad block parallel with the Satpura strike. During the subsequent, post-Cambay Shale evolution of the basin, drape-fold structures were formed over fault scarps and/or horsts. Early Tertiary volcanism is conspicuous along the west coast of India and is manifested by flood basalts, dike swarms, and eruptive centers. The volcanic activity and the incipient faulting which led to the subsidence of the Cambay graben basin probably are related to the opening of the northwestern Indian Ocean along the Central Indian and Carlsberg Ridges. As a result of the subsidence of the basin floor, compressional stresses (stressing) were developed in the crustal layers. These stresses were relieved by the uplift of many fault blocks in the sagging basin floor. The location of the Cambay basin at the junction of three ancient Precambrian tectonic trends--the Aravalli-Delhi, Satpura, and Dharwar--is significant. The reversal of the fault blocks is believed to have been caused by unstressing. This stage may have been controlled by the rejuvenation and interaction of the three ancient tectonic trends. The unstressed blocks then were readjusted in response to forces such as gravity, isostasy, loading, and unloading. The history of fault-block movement and rejuvenation of the old Precambrian lineation can be applied directly to petroleum exploration. The relative position of a fault block in the basin controls the deposition of source materials and reservoirs within it. Furthermore, the time of reversal of basement blocks is of significance, both from the standpoint of dating the deposition of lenticular reservoir sandstones, and the development of unconformity traps.