Properties Of Shale Research Articles

Geochemical and mineralogical controls on the geomechanical properties of the Eze-Aku Shale: Implications for a potential hydrocarbon reservoir

Oil and Gas Shales are becoming major contributors to the daily crude output in the global energy market. Due to permeability concerns, they require hydraulic fracturing to be commercially productive. Analysing their geomechanical properties and mineralogical influences is key to understanding the fracability and production optimization of shale reservoirs. To this regard, this study evaluates the geomechanical, geochemical and mineralogical properties of the Eze-Aku Shale. Twenty Eze-Aku Shale samples were collected from four locations (Onoli-Awgu, Lokpanta, Okopsi and Aboine) in the Southern Benue Trough. The samples were analyzed to determine composition of major oxides and minerals using Energy Dispersive X-Ray Fluorescence (EDXRF) spectrometry and X-Ray Diffraction (XRD) technology respectively. Parameters such as static Young's modulus and Poisson's Ratio were determined following the International Society for Rock Mechanics (ISRM) standard to define the brittleness and fracability of the shale samples. Average mechanical properties ranged from 0.07 to 0.13 GPa and 0.7–9.8 for Young's modulus (E) and Poisson's ratio (v) respectively. The ratio of Young's modulus to Poisson's ratio negatively relates with clay mineral presence (Illite, Kaolinite and Muscovite) in Okposi and Aboine while in Lokpanta and Onoli-Awgu these parameters however, relate positively with Calcite and Quartz. Good hydraulic fracture performance is linked to brittleness and high Young's moduli, which is favoured, by high silica and carbonate content. This research thus reveals that the mineralogy of the Eze-Aku Shale has prevailing effects on its geomechanical properties. In Lokpanta and Onoli-Awgu however, the shale can be compared most notably to the Barnett Formation (Shale), Eagle Ford Shale and Marcellus Formation.

Micro- to nano-scale areal heterogeneity in pore structure and mineral compositions of a sub-decimeter-sized Eagle Ford Shale

Mineral and organic matter compositions & pore structures of fine-grained shale influence reservoir properties. To improve the understanding of spatial heterogeneity in core-sized samples, methods of microscale X-ray fluorescence (μXRF) mapping, (ultra-) small-angle x-ray scattering [(U)SAXS] and wide-angle X-ray scattering (WAXS) have been used to determine elemental, pore-structure variations at scales up to ~10 cm on two samples prepared at circular and rectangular orientations from a piece of Eagle Ford Shale outcrop in South Texas, USA. In addition, thin section petrography and field emission-scanning electron microscopy observations, X-ray diffraction (XRD), total organic carbon, and pyrolysis were utilized to investigate the potential spatial heterogeneity of pore types, mineral and organic matter compositions for cm-sized samples at both orientations. Overall, the siliceous‑carbonate mineral contents in these two samples (8 cm × 8 cm × 0.08 cm and 5 cm × 8 cm × 0.08 cm, in terms of width×length×thickness) of carbonate-rich Eagle Ford Shale vary between laminations at mm scales. For the circular sample, porosity and specific surface area (SSA) variations range from 0.82 to 3.04% and 1.51 to 14.1 m2/g, respectively. For the rectangular sample, values for porosity and SSA vary from 0.93 to 2.50% and 3.95 to 10.8 m2/g. By analyzing six selected sub-samples on each of two samples with (U)SAXS and XRD techniques, nm-sized pores are mainly interparticle ones in the higher calcite regions, where the porosity is also relatively lower, while the lower calcite regions consist of both interparticle and intraparticle pore types with higher porosity. Finally, the μXRF and (U)SAXS mappings are combined to generate porosity distribution maps to provide more insights about sample heterogeneity related to the laminations and fractures at our observational scales.

Evaluation of fracturability of shale reservoirs in the longmaxi formation in southern sichuan basin

Major breakthroughs have been made in the exploration and development of shale gas in the Longmaxi Formation in the southern Sichuan Basin, China. The previous have adopted various methods to study the fracturability of shale, but the quantitative characterization of the comprehensive properties of shale during hydraulic fracturing is still difficult. For this reason, in this study, taking the Longmaxi Formation shale in the Changning and Luzhou Blocks in the southern Sichuan Basin as an example, the mineral composition, petrophysical properties, rock mechanical properties and in-situ stress of the shale were systematically studied using X-ray diffraction, pulsed porosity-permeability analysis, rock mechanics and in-situ stress tests. Furthermore, the brittle mineral content, elastic modulus, and in -situ stress parameters were calculated, and the Analytic Hierarchy Process (AHP) method was adopted to establish a comprehensive evaluation index of shale fracturability. The research results show that the shale of the Longmaxi Formation in southern Sichuan is dominated by mixed shale facies, and it has the characteristics of high content of brittle minerals, low porosity, large compressive strength and Young’s modulus, and small value of in-situ stress difference coefficient. Therefore, the Longmaxi Formation shale has good fracturing conditions. TOC and quartz contents have important effects on the fracturability of the Longmaxi shale. The analytic hierarchy process was adopted to determine the weight coefficients of the modulus brittleness index, mechanical brittleness index, in-situ stress difference coefficient, rock compressive strength and TOC content. Furthermore, a comprehensive evaluation index of fracturability was constructed. Calculations show that the comprehensive fracability indices of shale in the Changning and Luzhou Blocks are 0.49 and 0.59, respectively. Moreover, the quality of shale in the Luzhou Block is better than that in the Changning Block, which is related to the organic matter and quartz content and the microscopic pore structures inside the shale.

Effect of silica diagenesis on porosity evolution of deep gas shale reservoir of the Lower Paleozoic Wufeng-Longmaxi formations, Sichuan Basin

Silica diagenesis is critical to reservoir properties of shale, including porosity and rock mechanical properties, thus exerting a significant effect on shale gas production, but the role it plays on porosity evolution of deeply-buried shale remains unclear. In order to address this issue, a suite of deep gas shale samples (5910–5965 m depth) recovered from the Lower Paleozoic Wufeng-Longmaxi formations (WF-LMX) of the Sichuan Basin was selected to study silica diagenesis in these deposits and its effect on porosity evolution by the use of optical, SEM and SEM-CL observations, geochemical analysis, and low-pressure gas adsorption experiments. TOC of the WF-LMX shale sample suite that was altered to the thermally overmature stage ranges from 0.63 to 6.70 wt% (average = 3.26 wt%). Quartz hosted by the studied shale samples is present as six forms, including detrital quartz, quartz overgrowth, siliceous skeletal fragments, aggregates of amorphous to euhedral microquartz, silica nanospheres, and matrix-dispersed microquartz. Silica involved in the diagenetic alteration of the WF-LMX samples appears to have been chiefly sourced from the dissolution of siliceous skeletal fragments (mostly radiolarians) and secondarily from the transformation of clay minerals and alteration of detrital K-feldspar. Detrital quartz played a minimal role in porosity preservation, whereas authigenic quartz influenced porosity evolution in two ways. Siliceous skeletal fragments, aggregates of microquartz, silica nanospheres, and early diagenetic matrix-dispersed microquartz formed a rigid framework that shielded organic pores from compaction. However, quartz overgrowth and the precipitation of late stage diagenetic microquartz reduced porosity by filling voids. We estimate that a moderate content of authigenic quartz (Sixs = 10–30%) is optimal for the development and preservation of porosity (especially organic porosity). Organic pores, the dominant and pervasive pore type in the deep shale gas play, appear to have been best preserved in samples containing less than 5.5 wt% TOC. It is noteworthy, however, that some of the larger organic pores in samples containing >5.5 wt% TOC have collapsed in response to compaction. It is apparent, then, that organic porosity of the WF-LMX deep shale has been largely preserved showing great potential for shale gas exploration.

Numerical Simulation of Oil Shale Retorting Optimization under In Situ Microwave Heating Considering Electromagnetics, Heat Transfer, and Chemical Reactions Coupling

Oil shale constitutes an important proportion of unconventional resources, and its efficient exploitation helps alleviate the Chinese oil shortage situation. Nowadays, microwave heating is a promising method for in situ development of oil shale. However, the corresponding numerical simulation lacks in guiding the retorting optimization under microwave heating. A novel pseudo three-dimensional model, considering electromagnetics, temperature field, and chemical reactions coupling was developed and implemented to investigate oil shale reservoirs’ retorting performance under microwave heating based on the finite element method (FEM). The effects of microwave power, antenna number, and antenna position were analyzed creatively to optimize the microwave heating parameters. Numerical results showed high microwave power increased the maximum reservoir temperature quickly near the heating well, but the thermal conductivity of oil shale dominated the temperature of distal formation. For a typical case of two antennas at 0.9 m spacing and 500 W, the maximum temperature can reach 443 °C at 100 days, and the kerogen near the wellbore quickly converts to hydrocarbon products. Moreover, increasing antennas can improve the heating rate, and the specific distance between two antennas should be designed based on the microwave power and oil shale properties.

The investigation of impact of temperature on mixed-mode fracture toughness of shale by semi-circular bend test

Unconventional oil and gas resources are important and have recently attracted attention. High temperature stimulation can effectively release the damage of water phase trapping, which was caused during the drilling and completion of hydraulic fracturing of shale gas reservoirs. The changes of physical and mechanical properties of shale under high temperature is of significance to the safety and efficiency of hydraulic fracturing. This study investigated the effect of temperature on seismic velocity, porosity, permeability, and mixed-mode fracture toughness of shale. Shale samples are separated into two groups, one group of 12 samples to test porosity, permeability and velocity, and the second group of 12 samples to test the fracture toughness of shale. The results showed that as the temperature increased, the color of the shale sample lightened, and seismic velocity decreased while the permeability and porosity increased. The results also revealed that as the temperature was raised to 400 °C–600 °C, seismic velocity, shale permeability, and porosity all increased. Furthermore, the mixed-mode fracture toughness was reduced, indicating that the threshold temperature of the shale was around 400 °C. The threshold value obtained can provide a basis for field evaluation and the potential application of high-temperature treatment. A numerical model was developed to simulate fracture propagation in SCB (semi-circular bend) samples subjected to thermal treatment. The numerical simulation agreed with the experimental results, indicating that the high temperature promoted fracture propagation and had a higher stress concentration at the fracture tip.

Differences in micromechanical properties of shales from different depositional environment: A case study of Longmaxi marine shale and Yanchang continental shale using nanoindentation

An understanding of the mechanical properties of reservoir shale is of great significance for the efficient development of shale gas. Both marine and continental shale gas reservoirs in China have considerable development potential, but their different depositional environments may lead to substantial differences in their mechanical properties, which can result in production efficiency differences. In this study, nanoindentation, X-ray diffraction, backscattered electron imaging, and energy-dispersive X-ray spectroscopy were used to determine and analyze the mechanical properties and microtexture of marine and continental shale samples. The geogenesis of the microtexture of marine and continental shales and its influence on the mechanical properties were discussed. The results show that the elastic modulus of marine and continental shale samples are similar, but the hardness of latter is greater. The similar elastic modulus of the two shale samples may result from similar mineralogy. Due to differences in deposition and diagenesis, the marine shale sample forms a clay support matrix and the continental shale sample forms a rigid clastic support matrix, which results in lower hardness in the former and higher hardness in the latter. The low hardness of the shale with a clay support matrix indicates that it may be subject to more severe proppant embedment issue. The experimental results provide a useful reference for the development of these two types of shale gas reservoirs.

Comprehensive Review of Property Alterations Induced by CO2–Shale Interaction: Implications for CO2 Sequestration in Shale

CO2–shale interaction performs a crucial role in determining the capacity and leakage risk of CO2 storage in shale reservoirs. In this paper, the alterations of physical and chemical properties of shale triggered by CO2–shale interaction are reviewed, and then the implications for CO2 sequestration in shale formations are discussed. CO2–shale interaction induced the mineral alterations in shale and then further induced the pore structure alterations. The pore structure alterations are mainly controlled by mineral dissolution/precipitation and extraction and CO2 adsorption induced swelling in shale, which is closely related to the reservoir pressures and temperatures. Furthermore, the mineral and pore structure alterations may also influence the wetting behavior of shale. After CO2 exposure, the contact angle of shale increased, indicated the weakening in the hydrophilicity of the shale surface. The microscopic property alterations induced the macroscopic mechanical properties of shale to be weakened after CO2–shale interaction. The permeability variation of shale is significantly influenced by chemical–mechanical coupling effects including mineral dissolution/precipitation, adsorption induced swelling, wettability, and mechanical weakening induced by CO2–shale interaction. The shale property alterations will ultimately affect the CO2 storage capacity and security in shale. Future research needs to focus on the CO2–shale interaction covering multiple spatial and temporal scales at in situ conditions and considering the chemical–mechanical coupling effect on CO2 sequestration in shale.

Controlling effect of saline sedimentary environment on enrichment and exploitation of shale gas and oil in lacustrine basin

The salinity of continental lacustrine basin has a great influence on the properties of shale. The main objective of this paper is to present the characteristics of shale in different saline stages. In this study, we restored the saline process by the Kauchi method and evaluated the hydrocarbon generation capacity, reservoir property, oiliness and exploitability of shale in different saline stages. The sources of organic matter and paleoproductivity may vary among saline stages. Organic matter mainly originates from coccolithophyta and dinoflagellate in the saltwater stage, demonstrating the highest paleoproductivity. Meanwhile, paleosalinity has an important effect on the lithologic assemblage and mineral composition of shale, which controls its reservoir properties, oiliness and compressibility. The lithology in the saltwater stage is dominated by lamellar argillaceous limestone/calcareous mudstone and lamellar limestone, with good original physical properties. The carbonate content in such stage is the highest, making it easy to dissolve into dissolution pores and thus increasing the porosity and saturation of movable fluid. The high hardness of carbonate gives optimum compressibility to shale.

Integrated optimization design for horizontal well spacing and fracture stage placement in shale gas reservoir

Horizontal well drilling and hydraulic fracturing technologies play an essential role in improving gas recovery from shale reservoirs. However, they are expensive technologies and resource intensive production strategies. Optimization design of horizontal well spacing and fracture stage placement helps in striking a balance between gas production and economic benefits. However, previous researches relied mainly on numerical simulation technique which is computationally expensive and time-consuming. To reduce the computational burden, a novel multi-fidelity support vector regression (MFSVR) surrogate model assisted horizontal well spacing and fracture stage placement integrated optimization method, namely WSF-MFSVR, is proposed in this study. In the WSF-MFSVR method, both low-fidelity (LF) and high-fidelity (HF) numerical simulation models were applied to establish the multi-fidelity (MF) surrogate model so as to lessen the computational burden and guarantee its quality. In order to enhance the evaluation accuracy, the particle swarm optimization (PSO) algorithm was adopted to find the optimal hyper-parameters of the MFSVR model. Two cases with different wells and fracture types based on the shale gas reservoir with Barnett shale properties were employed to verify the WSF-MFSVR method. The results indicated that a combination of 300 H F and 3500 LF samples was the most suitable for establishing the MFSVR model to approximate the numerical simulation model. In terms of computational efficiency, the WSF-MFSVR method was about 50 times faster than the HF numerical simulation model-based method. Furthermore, the relative hyper-area difference (RHD) and overall spread (OS) of the WSF-MFSVR method were similar to that of the HF numerical simulation model-based method. However, the RHD and OS of the WSF-MFSVR method were superior to that of the LF numerical simulation model-based and single-fidelity support vector regression model-assisted methods. The data of these indexes quantitatively showed the superior convergence and diversity of the final optimal solutions obtained by WSF-MFSVR method.

Oil-bearing evaluation of different lithofacies in Da’anzhai Member, Central Sichuan Basin: implications for shale oil development

The Jurassic Da’anzhai Member of the Sichuan Basin has good prospects in shale oil exploration and development. However, the lack of research on the relationship between different lithofacies and oil-bearing property restricts the research on the geological theory and further exploration and development of shale oil in Da’anzhai Member. Based on core, fluorescence thin sections, rock pyrolysis, total organic carbon (TOC), extraction of chloroform bitumen ‘A’, and nuclear magnetic resonance (NMR) tests, the oil-bearing characteristics and reservoir physical properties in different lithofacies of Da’anzhai Member were analyzed. The results suggest that the oil-bearing and physical properties of shale are better than shell limestone and their peperite. The crude oil discharge from thick shale is limited because of the petrophysical property difference. The Da2b layer thick shale has the best shale oil exploration and development potential, which is the focus of the next step.

Evaluation of the Oil-Bearing Properties of Shale and Shale Oil Mobility in the Fengcheng Formation in the Mahu Sag, Junggar Basin, Northwest China: A Case Study of Well Maye-1

Due to an increasing energy demand and the depletion of conventional oil, there is ever increasing demand for unconventional shale oil and gas resources. As the most hydrocarbon-rich sag in the Junggar Basin, the development prospects for shale oil in the Mahu Sag have become a focus of research. However, so far, there have been few studies of the oil-bearing properties of shale and shale oil mobility in the sag. This paper redresses this using a range of methods, such as pyrolysis and multi-temperature step pyrolysis. The results show that the Fengcheng Formation shales are generally good quality source rocks. The main body of the shale is low mature-mature, and the type of organic matter is mostly Type II kerogen. In the depth intervals at 4616.45~4640.30 m, 4661.25~4695.20 m, 4728.30~4759.80 m, 4787.60~4812.30 m, and 4876.70~4940.25 m, the oil-bearing properties of the shale and shale oil mobility are good, with an average S 1 of more than 1.5 mg/g, OSI of more than 100 mg/g.TOC-1, a ratio of free/adsorbed oil ( S 1 − 1 + S 1 − 2 / S 2 − 1 ) of more than 3, and a ratio of free/total oil ( S 1 − 1 + S 1 − 2 / S 1 − 1 + S 1 − 2 + S 2 − 1 ) of more than 80%. The second member (P1f2) and the lower part of the first member (P1f1) of the formation offer the most promising commercial prospects. Shale oil mobility in the formation is greatly affected by the abundance of organic matter. The higher the TOC value, the greater the hydrocarbon generation capacity, and the better its adsorption capability in the shale. The Fengcheng Formation shale is mature, and shale oil mobility is good. Impacted by the main reservoir space, the felsic shale in the formation has optimal shale oil mobility, with the shale oil being characterized by self-generation and self-storage, and accumulation in adjacent layers.

Source rock properties of Permian shales from Rajmahal Basin, India

Source rock properties of Permian shales from Rajmahal Basin, India

Application of mathematical statistics to shale gas-bearing property evaluation and main controlling factor analysis

Gas-bearing property evaluation and main controlling factor analysis have remained a concern in shale gas research. The application of principal component analysis, an important mathematical statistical method, in gas-bearing property evaluation and main controlling factor analysis of the Longmaxi shale in the Weirong area, Sichuan Basin, was examined. The Longmaxi shale exhibits high heterogeneity, manifested in the organic matter abundance, mineral composition, and pore structure. Seven geological factors, including the temperature, pressure, TOC content, clay content, brittle mineral content, pore volume, and specific surface area (SSA), were selected in principal component analysis. Four principal components with geological significance, such as mineral composition, formation condition, pore structure, and organic matter abundance, were extracted through principal component analysis, and further constituted a comprehensive factor. Shale gas-bearing properties were evaluated according to the score of the comprehensive factor. The Longmaxi shale could be identified as exhibiting good, medium, and poor gas-bearing properties based on the comprehensive factor scores of these samples. According to each geological factor’s contribution to the comprehensive factor, combined with geological analysis, it could be considered that gas-bearing properties are primarily controlled by pore volume, SSA, and clay content, followed by TOC content, brittle mineral content, temperature and pressure.

Review of the Generation of Fractures and Change of Permeability due to Water-Shale Interaction in Shales

In shale development, water-based liquids are injected into the formations. In this process, water can interact with shales, especially with clay content. The interaction can lead to some phenomena, including clay swelling, reduction of mechanical properties of shales and fractures, generation and propagation of fractures, particle detachment, and permeability change. All the phenomena can impact productivity during the development, thereby impacting our investment and return on investment (ROI). So far, many researchers have put their time and efforts into this topic, and many articles have been published. However, some discrepancies still exist in shale reservoirs regarding the role of the interaction between water and shale, especially the impact of clay swelling. Some believe that clay swelling causes formation damage, mainly impairing shale permeability. Others state that fractures can be induced because of clay swelling, leading to the enhancement of shale permeability. So far, few articles have reviewed the various views on this interaction. Additionally, the relationship between each phenomenon is not discussed. In this paper, we try to draw a clear picture of water-shale interaction by reviewing the published studies, mainly focusing on experimental methodology and experimental results. Based on the review, we summarized the influencing factors as well as the mechanisms about the formation of fractures and change of permeability due to water-shale interaction. In water-shale interaction, the induced fractures are generated by the combined effects from clay swelling, reduction of mechanical properties of shales and fractures, and stress anisotropy. Shale permeability can be enhanced if the generated fractures can form an effective flow channel. However, if the generated fractures cannot serve as an effective flow channel, shale permeability will be impaired by clay swelling, water blocking, stress-sensitive, etc.

Dynamic mechanical properties and constitutive model of shale with different bedding under triaxial impact test

With the gradual depletion of traditional energy sources such as oil and natural gas. As an unconventional energy that can replace traditional resources, shale gas has attracted the attention of the world energy department. The storage environment of shale gas (oil) is usually accompanied by in-situ stress, and the exploitation of shale gas is actually a dynamic process. Therefore, it is of great significance to study the dynamic mechanical characteristics of shale under in-situ stress. In this paper, the dynamic mechanical parameter and constitutive relationship of shales with different bedding (0°, 30°, 45°, 60°, 90°) was studied by the triaxial SHPB tests with the confining pressure from 0 to 15 MPa. The effects of confining pressure on the mechanical properties of shale with different bedding were discussed from the aspects of the dynamic compressive strength, elastic modulus, failure strain, energy characteristics as well as the dynamic failure mode. The experimental results showed that, the dynamic mechanical properties of shale mainly depended on the interaction of the bedding dip angle and various confining pressures. The failure modes of shale under confining pressure mainly present compression shear failure or only damage crack. In additional, a modified dynamic constitutive model of shales was based on the ZWT viscoelastic constitutive relationship, which simplified the low frequency term and took into account shale material damage characteristics. The modified constitutive model is simple in structure and can predict the strength characteristics of shale under confining pressure in a certain range when the basic mechanical parameters and empirical parameters are known.

Experimental investigation of the mechanical properties of mud shale under water-bearing conditions and its applications.

Mud shale, used in drilling engineering, is prone to hydration and expansion, resulting in creep deformation that leads to wellbore shrinkage and pipe sticking incidents. Studying the creep characteristics of mud shale is significant for designing a reasonable well structure and determining the lower limit of drilling fluid density. The influence of moisture content on rock strength and creep mechanical properties were studied using water absorption, uniaxial compression, and creep tests. Test results show that with an increase in the moisture content, the mud shale was damaged and softened; moreover, the elastic modulus decreased with increase in moisture content. Under the same load level, the instantaneous strain increased with increasing moisture content. Under different loading stresses, the creep of the rock had nonlinear characteristics, which could be divided into three different creep stages: attenuation, second, and accelerated creep. A new improved creep model based on the Nishihara model was established to describe the accelerated creep characteristics of mud shale under different moisture contents. The ageing degradation and water-bearing weakening effects were introduced. The Levenberg–Marquardt nonlinear least-squares method was applied to invert the creep parameters. The results show that the simulated creep curves, generated using the new creep model, conform to the experimental ones. The relationship between the drilling fluid density and wellbore shrinkage ratio can be defined using this model; it provides a reference for reasonably determining the drilling fluid density.

Time-Sensitive Characteristics of Bedding Shale Deterioration under the Action of Drilling Fluid

Abstract Fractures continuously extend and expand along bedding shale formations under the action of drilling fluid and eventually form a complex fracture network, which greatly reduces the strength of the rock. To determine the effect of the drilling fluid action time on the physical and mechanical properties of shale, nuclear magnetic resonance tests are carried out on shale soaked in oil-based drilling fluid for different soaking times. The fluid absorption rate of shale takes the form of a power function. The equations relating the shale mass, porosity, and permeability to soaking time are established. Then, in a sonic time-difference test, the change in the dynamic elastic parameters with the immersion time are observed. According to a triaxial strength test, the failure form and the deterioration degrees of the layered shale in different loading directions with immersion time are analyzed. Numerical simulation of the deterioration degree of shale under different water content conditions is carried out. When the water content increases, the collapse density of the surrounding rock of the well wall increases significantly. Finally, considering the anisotropy of bedding shale, the inclination angle, azimuth angle, and drilling fluid immersion time are substituted into the rock mechanics parameter deterioration model, the three pressure profiles of the formation are corrected, and the safe drilling fluid density window of the target interval is given.

Nanoindentation investigation of mechanical and creep properties of continental Triassic Yanchang Formation shale, Ordos Basin

The mechanical and creep properties of shale have a great impact on wellbore stability and artificial fracturing performance during shale gas exploration. We have applied nanoindentation to study the preceding two aspects of the lacustrine Triassic Yanchang Formation shale in Ordos Basin on the microscale, which is the representative exploration target for shale gas occurring in continental shales in China. A massive nanoindentation campaign finds that the Yanchang shale is highly mechanically heterogeneous in local areas but statistically homogeneous in large areas. The sequentially increasing indentation loads (5–400 mN) result in a two-stage change of values of Young’s modulus and hardness, i.e., descending first and then remaining steady with a turning point at approximately 300 mN, which suggests that the large indentation load of not less than 300 mN can detect the mechanical response of bulk shale on the microscale. In addition, the indentation tests reveal a strong anisotropy of mechanical properties of Yanchang shale, as the measured Young’s modulus and hardness in the bedding plane parallel are much larger than those in the bedding plane normal direction. Furthermore, the Yanchang shale presents strong creep behavior and weak fracture toughness, which are different from those of current gas-producing marine shales worldwide. We attribute this to the higher content of clay minerals and relatively more loose texture of the Yanchang shale. In particular, the creep strain-rate sensitivity ( m) is calculated to be 0.102–0.134, suggesting that the dominant deformation mechanism of the lacustrine Yanchang shale may be dislocation creep.

The Paleozoic petroleum system of the Molla-Bismil area (Diyarbakır Basin, Turkey) and source rock properties of Lower Silurian (Llandovery) organic-rich shale

The Molla-Bismil area is a petroleum province, which hosts predominantly Paleozoic oil fields in the foreland area of the Diyarbakır Basin. The Arpatepe, Bahar, Yeniev, and Çalıktepe fields are Paleozoic oil field discoveries in the Molla-Bismil area to-date and have consequently been the focus of considerable research. This significant breakthrough reveals that the deep-wells in the Molla-Bismil area have proven the existence of a Paleozoic petroleum system. Prospective source rocks are located stratigraphically above the upper part of the Bedinan Formation (Upper Ordovician) reservoir, near the base of the Dadaş Formation (Llandovery, Dadaş-1 member). The lithology of the lower part of the Dadaş-1 member, also known as hot shales in the Molla-Bismil area, are typified by organic-rich brownish-black colored shale containing bitumen and thin limestone beds. New well data assists with the regional definition and correlation of typical source rock properties within the Diyarbakır Basin. Subsurface stratigraphy was derived for several deep wells from the Molla-Bismil area and core or drill cuttings from the Çatak-1, Bahar-1, Göksu-1R and Çalıktepe-2 wells were studied and reviewed for lithological and geochemical information. The understanding and prediction of the geochemical characterization of the Lower Silurian (Llandovery) organic-rich shales relevant for hydrocarbon production are crucial for Turkey's fossil fuel supply. Based on new drilling data, we re-examined the properties of the Llandovery organic-rich shales in the Molla-Bismil region. This study brings together new and previously unpublished knowledge about the Paleozoic plays of SE Turkey.