Shale Systems Research Articles

Evaluating microdistribution of adsorbed and free oil in a lacustrine shale using nuclear magnetic resonance: A theoretical and experimental study

The occurrence states (adsorbed or free) directly control the transport and production of shale oil, and free oil is the most common potential product available using existing technologies. A variety of theories and experimental methods have been developed to estimate the adsorbed and free oil amounts in shale pore-fracture systems, however, it is difficult to clarify the microdistribution characteristics of shale oil in in-situ pore systems using these methods. In the study described here, by integrating experimental and theoretical models, an effective method was developed to reveal the microdistribution of oil confined in nanoporous shales from the Dongying Sag, in the Bohai Bay basin, China. Centrifugation–nuclear magnetic resonance (NMR) experiments were combined with the modified Langmuir equation, and then applied to estimating amounts of adsorbed and free oil. And the microdistribution characteristics of shale oil were then analyzed by the adsorption ratio theoretical model. Furthermore, the mechanisms of controlling the adsorbed, free amounts and microdistribution of shale oil were also discussed. The primary results demonstrated that the modified Langmuir equation (Langmuir-like equation) was an effective and accurate technique for evaluating the adsorbed and free oil amounts in shales. We estimated that adsorbed and free oil amounts ranged from 5.8023 to 29.7995 mg/g, and from 3.9510 to 25.6410 mg/g, respectively, at a temperature of 20 °C, while the adsorbed oil weight ratios were 0.2778–0.7023 (mean 0.5438). The average value of the adsorbed oil density was approximately 2.0231 g/cm³, which was 2.6994 times that of the free oil. The average adsorbed layer thickness was 0.7433 nm, which equaled nearly two molecular diameters. The adsorbed and free oil microdistribution was clearly described by the adsorption ratio theoretical model and the T₂ spectrum. The adsorbed oil was mainly confined to micropores, while free oil was stored in meso- and macropores—and that pore microstructures affected shale oil microdistribution characteristics. The amount of adsorbed oil was mainly controlled by micropore volume and specific surface area, while the amount of free oil was closely associated with total volume of the larger pores. We also noted that the more complex the pore structure, the lower the free oil content and the higher the adsorption ratio. The amount of adsorbed oil was closely related to the shale composition, and increased with TOC content. The amount (ratio) of adsorbed oil also increased with increasing clay mineral content, and was negatively proportional to the quartz + feldspar content. The authors are confident that the study described in this paper has delivered new insights into the microdistribution of adsorbed and free oil in shale pore-fracture systems.

Differences of Pore Features in Marine Shales between Lower Cambrian and Lower Silurian Formations of Upper Yangtze Area, South China

Lower Cambrian shale and lower Silurian shale are both typical of oil-prone kerogen and siliceous composition, but different in thermal maturities. Porosity differences were determined in marine shales between the two shales. Measurements were utilized including organic geochemistry, XRD, scanning electron microscopy (SEM) and N2 gas adsorption. Pore volume (PV) of lower Silurian shale was approximately 1.5 times higher than that of lower Cambrian shale, and pore surface area (PSA) of lower Silurian shale was almost 2.5 times higher than that of lower Cambrian shale. Lower Cambrian shale and lower Silurian shale possess similar materials, but distinctive thermal degrees. Evolution mechanisms of different types of pores, especially organic matter (OM)-hosted pores, may trigger this different pore features. Pores of rigid framework are the residue of primary interparticle pores during the burial history. Pores associated with clay flakes can be preserved well adjacent to rigid grains or secondary minerals acting as rigid frameworks or grain supporters. Dissolved pores in both lower Cambrian shale and lower Silurian shale barely contribute to the total porosity and mean little to the permeability. Both excessive OM content and over thermal maturity are detrimental to development of OM-hosted pores. Rigid particles, clay flakes, and OM commonly co-exist within shale matrix. Rigid grains act as supporters, clay flakes confine ample space, and OM first migrates into and provides secondary OM-hosted pores. In this condition, pores can be preserved owing to associating matrix with good mechanic and chemical stability. The significant differences of structural settings result into various hydrocarbon explosion efficiency and different pressure circumstance, which consequently leads to the different pore features between the two shales. For lower Cambrian shale, overpressure circumstance diminish if hydrocarbon expels outside of the shale system, and OM-hosted pores destroy through compaction. Sustaining overpressure and abundant residue hydrocarbon (migrated OM) make positive contributions to the pore properties, in terms of numbers, diameters and connectivity of the lower Silurian shale samples.

Effects of pressure on gas generation and pore evolution in thermally matured calcareous mudrock: Insights from gold-tube pyrolysis of the Eagle Ford Shale using miniature core plugs

Together with an increased interest in deep petroleum and shale gas exploration over the last decade, the effects of pressure on gas generation and pore evolution in organic-rich shales have received renewed attention. In this study, miniature core plugs drilled from a thermally matured Eagle Ford Shale sample were pyrolyzed in sealed gold tubes to investigate the effects of pressure on gas generation coupled with pore evolution in the presence of a relatively intact rock fabric. The gold-tube-capsuled samples were isothermally heated at a temperature of 425 °C for 36 h under different confining pressure conditions (10, 25, 35, 50, 68, 80, and 120 MPa), with maturation being induced from the original oil window to the gas window.Experimental results show that increasing the confining pressure from 10 to 120 MPa has initially retards and then promotes the generation of low molecular hydrocarbons (C1–C5 alkanes), whereas gas dryness (C1/C1–5, vol%) increases continuously from 51% to 63% in this pressure range. The inflection pressures that correspond to the maximum retardation of the generation of individual hydrocarbon compounds are shifted to higher values with increasing the molecule carbon number, e.g., 35 MPa for methane, 50 MPa for ethane to butane, and 68 MPa for pentane. Similar pressure effects have also been found for liquid hydrocarbons (C6–14 hydrocarbons and C14+ compounds), with a single inflection pressure of 68 MPa. These observations indicate that high pressure inhibits residual oil cracking but simultaneously favors generation of methane-rich gas. A mechanism for the interaction of retained hydrocarbons and porous matured kerogen (and/or pyrobitumen) is thus suggested to explain the enhanced methane generation. The extent of such interactions is highly dependent on petroleum expulsion efficiency from an intact rock fabric.BET specific surface area and pore volume measured by N2 adsorption decrease significantly for samples matured at 10–35 MPa and then increase at confining pressures above 50 MPa. The simultaneous variations in pore development and methane generation with increasing confining pressure indicate that the observed effect of confining pressure on the evolution of the pore structure of shales depends on both oil retention and gas generation. Our experimental results provide some new insights into gas generation and pore evolution in shale systems, and the retardation effect of pressure on hydrocarbon generation and expulsion as well as pore evolution may provide a mechanism for the Type II kerogen-dominated oil-prone shales to become potential shale gas reservoirs.

Contribution of gas adsorption–desorption in Marcellus shale for different fractured well configurations

Gas adsorption onto the shale system carries significant importance in accurately forecasting gas production and estimating underground reserves. For the Marcellus shale system, the adsorption of gas also plays a critical role in ultimate recovery and overall reserves quantification. Yet, the effect of different adsorption characteristics in different Marcellus shale regions is not systematically analyzed together. In this study, the contribution of different gas adsorption phenomena in Marcellus shale for different fractured well configurations is investigated. The objective is to understand the reservoir production responses under various adsorption characteristics and well design. For this analysis, a mechanistic Marcellus shale model under confining stresses is numerically simulated with the available literature data. After that, six samples containing adsorption characteristics of different Marcellus shale regions are taken from the literature and specified in the model for accurately defining the adsorption physics in the shale system. In the end, two different well configurations including the fractured vertical and horizontal well are specified in the model separately to analyze the impact of gas desorption on production response. The analysis indicates that the gas desorption improves the overall gas production by a maximum of 5% in a single-stage multi-clustered fractured horizontal well. In addition, the effect of desorption is found to be minimal during initial flow periods, and considerable at longer flow periods. Additionally, the gas desorption is found to be more responsive towards high surface area and large fracture networks. Finally, it is determined that a fractured horizontal well is a viable option that allows high gas desorption in Marcellus shale. This study, hence, aids widely in deciding better production strategies based on adsorption characteristics for producing Marcellus shale.

Mutual Impacts between Mineral Alteration and Bitumen Dissolved Organic Acid Evolution in Hybrid Shale System: From Lamina-Scale to Lithofacies-Scale

Mutual Impacts between Mineral Alteration and Bitumen Dissolved Organic Acid Evolution in Hybrid Shale System: From Lamina-Scale to Lithofacies-Scale

Examining and applying the theory of “exploring petroleum inside source kitchens” for continental shale oil: A case study from the Kong 2 member of the Cangdong sag in the Bohai Bay Basin, China

Continental shale oil to be studied urgently is an important unconventional “source rock oil and gas” and key domain of “exploring petroleum inside source kitchens”. Based on the “source rock oil and gas” theory and the thought of “exploring petroleum inside source kitchens”, this paper established the ”six determination” exploration workflow for continental shale oil (i.e., determining the background, source rock, reservoir, play, resources, and sweet spot), which geological characteristics and exploration workflow are significantly different from conventional hydrocarbon. A case study was conducted by the workflow in the Kong 2 member (Ek2) of the Cangdong sag in the Bohai Bay Basin, China. Semi-deep to deep lacustrine facies belts and many gentle slope structures (belts) were widespread during Kongdian Formation depositing, thus providing favorable conditions for the formation and large-area accumulation of shale oil. Ek2 developed broader-distributed, and thick-bedded dark mudstone and oil shale, which exhibit high TOC, a good kerogen type, and great hydrocarbon-generating potential. Siltstone to fine sandstone and mud to micritic dolomite reservoirs were found within the low-dip slopes and central zone, which are thick, overlapped, abundant high-angle fractures, and exhibit low porosity and ultra-low permeability. Sandstone-type and dolomite-type shale oil of Ek2 characterized source–reservoir integration and five types of sources–reservoir configurations. They mainly overlapped at the front end of the braided river delta in the slope zone and in the sag center, where are superimposed vertically, and are connected horizontally with conventional structural–lithological oil pools in the up-dip slope. The median geological resources of the two classes shale oil were 5.26×108/t, with the remaining resources accounting for 90% of the total and moderate buried depths, thus the exploration potential is great. Several special exploration wells have obtained industrial oil flow. There are two types of sweet spots: low permeability sandstone layers and interbedded layers of oil shale and dolomite. A few favorable sweet spots were identified as targets for subsequent exploration. Then, three aspects of thinking and recommendations to solve the next exploration direction and technical problems were proposed, which will provide important reference and theoretical guidance for the further exploration of the same type of shale system in China and the world.

The Influence of Oil Composition, Rock Mineralogy, Aging Time, and Brine Pre-soak on Shale Wettability.

Experimental and field studies have indicated that surfactants enhance oil recovery (EOR) in unconventional reservoirs. Rock surface wettability plays an important role in determining the efficacy of this EOR method. In these reservoirs, the initial wettability of the rock surface is especially important due to the extremely low porosity, permeability, and resulting proximity of fluids to the solid surface. This study is designed to investigate the effect of oil components, rock mineralogy, and brine salinity on rock surface wettability in unconventional shale oil/brine/rock systems. Six crude oils, seven reservoir rocks, and seven reservoir brine samples were studied. These oil samples were obtained from various shale reservoirs (light Eagle Ford, heavy Eagle Ford, Wolfcamp, Middle Bakken, and Three Forks) in the US. SARA (saturates, aromatics, resins and asphaltenes) analysis was conducted for each of the crude oil samples. Additionally, this study also aims to provide a guideline to standardize the rock sample aging protocol for surfactant-related laboratory experiments on shale reservoir samples. The included shale reservoir systems were all found to be oil-wet. Oil composition and brine salinity showed a greater effect on wettability as compared to rock mineralogy. Oil with a greater amount of aromatic and resin components and higher salinity rendered the surface more oil-wet. Rock samples with a higher quartz content were also observed to increase the oil-wetness. The combination of aromatic/resin and the quartz interaction resulted in an even more oil-wet system. These observations are explained by a mutual solubility/polarity concept. The minimum aging time required to achieve a statistically stable wettability state was 35 days according to Tukey’s analysis performed on more than 1100 contact angle measurements. Pre-wetting the surface with its corresponding brine was observed to render the rock surface more oil-wet.

Porosity Evolution In Lacustrine Organic-Matter-Rich Shales With High Claly Minerals Content

Pore structure is a major factor affecting the storage space and oil-bearing properties of shales. Mineralogy, organic matter content, and thermal evolution complicate the pore structures of lacustrine shales. In this study, the porosity evolution of organic-matter-rich shales from the Cretaceous Nenjiang Formation in the Songliao Basin, Northeast China, are investigated using thermal simulation experiments and in-situ scanning electron microscope analysis. Three findings were obtained as follows: 1) The pore system of shales from the Nenjiang Formation is dominated by inter-granular dissolution pores of plagioclase and intra-granular pores of illite-smectite mixed layers. Few organic-matter pores are observed. 2) New pores developing during thermal evolution are primarily organic matter pores and clay mineral pores, with diameters greater than 18 nm. Clay mineral pores with diameters of 18–50 nm are the principal contributors to porosity at temperatures between the low maturity stage and the oil-generation window, and organic matter pores with diameters of greater than 50 nm comprise the majority of pores generated between the gas-generation window and the high-/over-mature stages. 3) Porosity increases continuously with maturity, and the pore system varies at different maturity stages. Porosity evolution is controlled by illite content and organic matter abundance. Total pore volume correlates positively with illite content but negatively with organic matter abundance. These findings could provide guidance on shale oil evaluation in the Songliao Basin and assist in the ‘sweet-spotting’ of lacustrine shale systems across China.

Pore Structure, Fractal Features, and Oil Content Evaluation of Lacustrine Shale: A Case Study of First Member of Paleogene Shahejie Formation, NE China

The complex and heterogeneous pore structure and oil content of lacustrine shales introduce significant challenges in the exploration of shale petroleum systems. To further expand our geological understanding of lacustrine shales and provide guidance for hydrocarbon exploration, in this study, based on programmed and improved Rock-Eval pyrolysis, total organic content (TOC) measurements, scanning electron microscopy (SEM) observations, and N2 adsorption (NA) experiments, a systematic evaluation of the mineral composition, geochemical features, pore structure, and oil contents of the third member of the Paleogene Shahejie Formation (Es3) shale in the typical lacustrine hydrocarbon enrichment sag (Nanpu Sag, Bohai Bay Basin) is conducted. The fractal theory is selected to quantify the pore system’s heterogeneity; also, the relationships between the pore structure parameters and the oil contents and mineral composition are revealed. Our results reveal the geochemical features of the Es3 shale are excellent, and thus, they can be classified as a set of high-quality source rocks (average TOC of 4.2%, mainly type II kerogen, and in the mature stage). Based on the SEM and NA analyses, the intercrystalline pores dominate the pore system. Moreover, the mesopores contribute the most specific surface area (SA) and pore volume (PV) to the samples (average contribution rates of 74.7 and 75.0%, respectively). The fractal dimensions have relatively strong positive correlations with PV and SA, which means more heterogeneous and complex pore structures provide more storage space and adsorption sites for shale oil accumulation. The clay mineral content is the most important factor which controls the pore structure parameter, and high clay content indicates high SA and PV. According to proposed numerical movable and adsorption hydrocarbon calculation models, the TOC content is the dominant factor controlling the movable and adsorption oil contents, but other factors’ impact also cannot be ignored. Our study not only provides guidance for shale oil exploration in the study area but also broadens our understanding of the oil contents of lacustrine shale.

Assessing the Gas Potential of the Lower Paleozoic Shale System in the Yichang Area, Middle Yangtze Region

This study aims to characterize the geological properties and to evaluate the gas potential of the lower Paleozoic shales in the Yichang area by integrating a series of analyses on geology and geochemistry, well logging data, and 2D seismic interpretation. The thickness of the lower Cambrian Shuijingtuo shale is less than 10 m in the southeast but may exceed 120 m in the southwest area. The thickness of the upper Ordovician Wufeng shale and the lower Silurian Longmaxi shale (hereafter referred to as the Wufeng-Longmaxi shale) gradually increases in thickness from <10 m in the south to 40–50 m in the northeast. The organic matter of the above two sets of black shale is mainly dominated by type I and II1 kerogen. The thickness of black shale units with TOC > 2% is more than 10–20 m, commonly located at the bottom of the shale intervals. Black shales near the Huangling anticline have low thermal maturity due to its relatively shallow burial. The predominant minerals are quartz and clay minerals. Carbonate contents of the Shuijingtuo shale are relatively high compared to the Wufeng-Longmaxi shale. Pores are more developed in the Wufeng-Longmaxi shale than those in the Shuijingtuo shale. Natural fractures are common in the Shuijingtuo shale but are rare in the Wufeng-Longmaxi shale. The well logging and lab analytical results both indicate that the natural gas content in the black shales is relatively high. The prospective area of the Shuijingtuo interval for shale gas production is nearly 670 km2, located in the southwestern region. In contrast, the prospective area of the Wufeng-Longmaxi interval for shale gas production is approximately 1590 km2, situated in the eastern area.

Modeling and Simulation of Shale Fracture Attitude.

A large number of natural fractures are distributed in shale gas reservoirs. In-depth studying of the attitude of fractures is of great significance for the efficient development of shale gas. In previous studies, the complex three-dimensional discrete fracture networks (DFNs) and transport mechanisms were often not fully considered. In this study, the fully coupled multimechanism transport model and the complex discrete fracture networks (DFNs) model are developed to incorporate these complexities. The comprehensive transport model can couple multiple mechanisms such as slippage, diffusion, adsorption, and dissolution of shale gas. Moreover, the mechanisms of two-phase flow, reservoir deformation, real gas effect, and fracture closure are also considered. The three-dimensional DFN model can flexibly characterize the fracture attitudes, which means that the construction of the discrete fracture network is easier and faster. Under these frameworks, a series of partial differential equations (PDEs) were derived to describe transport mechanisms of shale gas in the shale fracture-matrix system. These PDEs were numerically discretized and solved by the finite element method. The proposed models are verified against gas production data from the field and validated against others’ solutions. This study numerically simulates the influence of different fracture attitudes on shale gas transport and analyzes the sensitivity of the model. The results and sensitivity analysis reveal that both fracture dip angle and strike direction will significantly affect the gas production, and the smaller the angle between the strike direction and the flow direction, the higher the shale gas production. The length, density, area, and shape of fractures also play important roles in shale gas transport. There is an ideal fracture density in the fracture network, and the suggested excessive fracturing is not economic. The shale fracture-matrix system modeling and simulation methods can improve the development of shale gas reservoirs and increase the gas production of wells.

Multiscale characterization of shale pore-fracture system: Geological controls on gas transport and pore size classification in shale reservoirs

A sound understanding of the pore-fracture system across all scales provides an in-depth look at the intricate gas transport mechanisms in shale reservoirs. We performed a comprehensive multiscale characterization analysis on the Longmaxi shale samples using five complementary techniques: low-temperature gas (N2) adsorption (LTGA), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), field emission scanning electron microscopy (FE-SEM), and X-ray computed tomography (CT) scanning. For pore size distribution (PSD) determination, LTGA (N2) analysis can detect small pores (2–300 nm sized), while MIP analysis is suitable for large pores or fractures (> 300 nm). NMR can reveal full-scale PSD characteristics of shale. Combining NMR with LTGA or MIP is recommended, since NMR alone would over- or under-estimate the pore size. The Longmaxi shale pores observed by FE-SEM imaging are of good connectivity and, by and large, are tens of nanometers sized. The scale-dependent analysis shows that the representative elementary volume (REV) for porosity of the Longmaxi shale based on FE-SEM imaging is almost 600 μm. As evident from the CT scanning, the connectivity of the entire shale pore-fracture system increased significantly after saturating the sample with water. The gas slippage (Klinkenberg) effect is significant at relatively low pressures. A second-order model would better estimate the intrinsic permeability compared with the traditional Klinkenberg equation. Microfractures manifest preferred orientation or alignment parallel to the shale bedding plane and are the dominant pathways for gas transport in shale. Finally, we proposed a new pore size classification of shale considering gas transport mechanisms: adsorption pores (pore size < 10 nm), slippage pores (10 nm < pore size < 1000 nm), and seepage pores or fracture-pores (pore size > 1000 nm). Although slippage pores dominate in terms of the total volumetric contribution of the Longmaxi shale, with a clear presence of adsorption pores, overall gas transport in shale is predominantly controlled by the seepage pores (fracture-pores), which constitute a very small portion of the total volume.

Synergetic Effect of Water, Temperature, and Pressure on Methane Adsorption in Shale Gas Reservoirs.

Adsorption is one of the most important forms of storage of gas in shale reservoirs. Shale gas adsorption in the actual reservoir is not only affected by individual factors such as water content, temperature, and pressure but also by the synergetic effect of these factors. In this study, we conducted laboratory experiments on methane adsorption in dry and wet shale at different pressures and temperatures. The synergetic effect of water content, temperature, and pressure on shale gas adsorption is explored. The results show that increasing temperature weakens the interaction between methane and shale and reduces adsorption capacity due to the exothermic nature of adsorption. Water reduces methane adsorption capacity by occupying adsorption sites and blocking pores in the shale system. Although temperature and water reduce methane adsorption individually, the effect of these two factors weakens each other. Temperature has a more significant effect on methane adsorption in shales with low water content, while water has a more remarkable impact on methane adsorption at a low temperature. Furthermore, the increase in pressure reduces the negative influence of water and temperature on methane adsorption. By quantitatively analyzing the relationship between methane adsorption in dry and wet shales, a predictive adsorption model for wet shale considering the influence of in situ conditions is proposed and validated. Validation shows that the proposed model has high accuracy and broad applicability to shales with different properties.

Geology still matters – Unconventional petroleum system disappointments and failures

Machine learning and factory drilling approaches have increased efficiency and improved the commerciality in many tight plays. However, not all the original resource estimates and potential opportunities have, been confirmed by the drill-bit. Although some of the commercial disappointments have been a result of policy decisions, more often they are due to partial or complete failure of the unconventional petroleum system and/or the hydrocarbon phase encountered. Studies have demonstrated that not all mudrocks are organic-rich, contain the appropriate kerogen type, have achieved the appropriate level of thermal maturity, have suitable unconventional reservoir properties, are able to retain hydrocarbons, or have the necessary resource density to be a viable tight rock target. An overview of six shale plays in this study (the Longmaxi Shale of China, the Silurian shales of eastern Europe, the Cambay Shale of India, the Barnett Shale in northeast Texas, the Eagle Ford Shale of South Texas, and the Waltman Shale of Wyoming) represent the diversity of potential geologic problems. It becomes apparent that, just as in the case of conventional exploration, successful unconventional exploration and development requires a full assessment of the petroleum system. Absence or limited effectiveness of one or more elements (i.e., source rock presence, quality, and thermal maturity, reservoir presence and quality, and retention) of the petroleum system is a primary driver for mismatch between resource expectations and results. • Exploration and exploitation of shale systems requires an understanding of all petroleum system elements. • Many of the exploration failures in shale systems could have been predicted prior to drilling. • Common causes of failure are wrong kerogen type and inappropriate level of thermal maturity. • Reservoir quality appears to be more associated with the ability to fracture than in inherent porosity and permeability.

Implications of thin laminations on pore structure of marine shale reservoir: Goldwyer Formation case study from Western Australia

The pore structure of a shale reservoir is a major control on hydrocarbon potential, yet shale pore systems are complex and affected by various factors. This paper focuses on the differences in pore structure between thinly laminated and massive black shale (MBSh) beds in the Ordovician Goldwyer-III shale, Canning Basin, Western Australia. A multiscale approach included image logs, core descriptions, thin sections, scanning electron microscope and X-ray diffraction analysis with low-pressure nitrogen and carbon dioxide gas adsorption tests. The results indicate that the Goldwyer shale comprises laminated beds of quartz silt and shale with thin beds of organic-rich clay, plus minor interbedded carbonate bands or concretions. The pore types are subjected to rock type, and the thinly laminated shale (LSh) is enriched in intergranular and intragranular pores. In contrast, the MBSh mainly comprises organic matter pores. The LSh is slightly enriched in mesopores but has negligible micropores. The mesopores are wedge-shaped and associated with an inorganic matrix of clay and pyrite. In comparison, the MBSh contains both mesopores and micropores. These pores are slit-like and related to organic matter and clay. The clay content and total organic carbon fluctuations control the development of mesopores and micropores in both the laminated and MBSh beds in the Goldwyer-III shale. The MBSh layers are suggested as the most important rock types for fluid flow via pore systems due to higher total pore volume, specific surface area and gas adsorption capacity.

Permeability prediction in tight gas reservoirs based on pore structure characteristics: A case study from South Western Iran

Abstract Porosity, pore structure characteristics, and permeability are among the key petrophysical properties of shale gas resources. Accurate characterization of these parameters in the unconventional gas shale systems has been proved to be challenging due to the uniqueness of the pore structures, mineral compositions, tightness, and pores hosted in the organic matter. In this study, the porosity, pore structure characteristics, and permeability of cored samples from the Garau shale formation located in the southwestern part of Iran were evaluated using a combination of laboratory methods. Multiple linear regression analyses were then utilized to develop empirical relationships between helium permeability values, porosity, and pore throat radii. Results showed that the best permeability predictors for the examined samples could be developed using the pore throat radius that corresponds to a mercury saturation of 55% and porosity. This approach helps develop a permeability prediction model for tight shale gas reservoirs based on pore structure characteristics, reducing cost and time.

The effect of tectonic deformation and preservation condition on the shale pore structure using adsorption-based textural quantification and 3D image observation

Tectonism significantly affects the pore characteristics of organic-rich shales. Here, two sets of shales with similar mineral compositions and total organic carbon (TOC) content were used to evaluate the response of pore structure to tectonic deformation through gas adsorption, FE-SEM, and Nano-CT. The stable region shales have superior porosity, pore volume, pore diameter, surface porosity of organic matter (OM), and pore connectivity. However, the deformed region shales show obviously low storage space, pore size, and connectivity. The OM pores of the stable region shales were well preserved due to the support of residual overpressure in the closed shale system. The larger pore size and better pore connectivity enable gas molecule to be much easier to diffusion and flow, thus leading to high yield after hydraulic fracturing. Conversely, the OM pores of the deformed region shales are commonly compressed and even closed, because of the absence of overpressure-associated supporting mechanism in a relatively opened shale system. Shale gas is difficult to transport in this kind of shale reservoir with poor pore structure parameters, resulting in limited yield. Furthermore, our work also provides 3D pore deformation information of shale reservoirs under complex tectonic episodes.

Organic petrology and geochemistry of Lower Cretaceous lacustrine sediments in the Chaoyang Basin (Liaoning Province, northeast China): Influence of volcanic ash on algal productivity and oil shale formation

Airfall volcanic ash deposited in the form of tuff layers is widely distributed in oil-shale bearing basins in western Liaoning Province, northeast China. In order to investigate the impacts of volcanic ash on algal productivity and the formation of organic-rich oil shales, the organic petrology and organic geochemistry of lacustrine sediments of the Lower Cretaceous Jiufotang Formation were investigated. Molecular geochemical data (the pristane/phytane ratio, the gammacerane index and the relative amount of β-carotane) indicate that they were formed in suboxic/anoxic depositional environments, with salinity fluctuations from freshwater to saline. Oil shales in the semi-deep to deepwater lake facies were mainly deposited under still and anoxic bottom water conditions, concomitant with water column salinity stratification. The relative abundances of diterpenoids and regular steranes indicate a limited terrigenous conifer plant contribution and a predominantly algal contribution to the organic matter. Blooms of algae contributing to high primary productivity, and anoxic depositional environments contributing to organic matter preservation, were key to organic-rich oil shale formation. Fish bones, ostracod shells, and alginite are present below the thick tuff layer. Alginite richness gradually increased from very low just above the tuff layer, to a higher concentration further above the tuff layer, indicating that during major volcanic eruptions, large quantities of volcanic ash led to water column poisoning, causing the sudden mass mortality of some aquatic organisms that were sensitive to turbid, acidified and toxic water. The increased proportion of brackish/saline-water dinoflagellates, which is corroborated by the high concentration of telalginite, abundant dinoflagellate-specific biomarkers (C31 4,22,23,24-tetramethylcholestanes), high values of the C27/C29 ααα-20R and C28/C29 ααα-20R sterane ratios, 4-methylsterane index, dinosterane index, and tetramethylsterane index, suggest that brackish/saline-water dinoflagellates show a positive response to volcanic ash input. Some specific brackish/saline-water dinoflagellates are present in organic-rich tuff laminae, indicating that during periods of minor volcanic eruptions or in intermissions between major eruptions, a minor volcanic ash input was more likely to result in rapid and efficient volcanic fertilisation effects and high-quality oil shale formation. Although the lacustrine oil shale system of the Jiufotang Formation shares some similar petrological and geochemical characteristics with the classical saline lacustrine oil shale system of the Green River Formation in the United States of America, the significant influence of airfall volcanic ash on algal productivity makes the formation mechanism of oil shales within the Jiufotang Formation strata quite different from that of oil shales within the Green River Formation.

Mechanism of wellbore instability in continental shale gas horizontal sections and its water-based drilling fluid countermeasures

The wellbore instability in the horizontal sections of continental shale gas wells in the Ordos Basin is a major engineering and technical problem that restricts the exploration and development of the shale gas resources in the Yanchang Formation of Upper Triassic of Mesozoic in the Yanchang Block. To solve this problem, this paper analyzed the characteristics of mineral components in shale by means of X-ray diffraction. In addition, its physical and chemical characteristics, specific surface area and microstructure were analyzed. On this basis, a shale water-based drilling fluid system (PSW-2) of low free water activity based on nano plugging was developed. And it was applied on site at five horizontal wells in continental shale gas reservoirs to ensure the wellbore stability of their long horizontal sections. And the following research results were obtained. First, the Yanchang Formation shale in this area has a high content of clay mineral, and it is a fractured formation of weak expansion, easy dispersion and multiple bedding, so the wellbore instability here is the result of the comprehensive action of mechanical factors, physical and chemical factors, drilling mechanical disturbance, etc. Second, the shale has average pore diameter is 4.494–8.502 nm and is characterized by obvious capillary action, strong water absorption capacity and uneven hydration, which result in the decrease of local shale strength, so sudden collapse tends to happen easily. Third, the API loss of PSW-2 system is less than 2.8 mL, the rolling recovery rate is 95.15% (close to the recovery rate of oil-based drilling fluid 98.25%), the linear expansion rate is as low as 1.38%, and the wetting angle increases from 26° of dry rock samples to 56.5°. Fourth, the compressive strength of the system after immersion increases to 95.806 MPa, which is close to the original rock strength (110.70 MPa). It is concluded that this water-based drilling fluid system can effectively ensure wellbore stability by blocking the pores of shale with micro nano components, reducing the activity of liquid phase to increase the inhibition, and weakening the multi-element collaboration of the capillary imbibition effect of shale.

Geological characteristics and shale oil potential of the lacustrine immature to low mature shale oil system: a case study of the second member of Kongdian Formation in Cangdong Sag, Huanghua Depression, Bohai Bay Basin, China

ABSTRACT The Second Member of Kongdian Formation (Ek2) shale oil system is a set of thick organic-rich lacustrine shales with great shale oil resources potential. The shales are oil-prone with high organic matter abundance (samples with TOC > 2% accounting for 72.6%) and low maturity (the Ro of samples between 0.42% and 0.84%). The Ek2 shale system is dominated by shales, sandstones, and carbonate rocks, which can be subdivided into various-mixed lithologies. The shales are primarily composed of clay minerals, quartz, feldspar, calcite, dolomite, pyrite, siderite, and zeolite, with no obvious predominant minerals. The brittle mineral content is high with an average content of 73.86%, which is conducive to reservoir stimulation. Physical properties and oil saturations vary significantly among different lithologies. Tight sandstones (average porosity 8.66%, average permeability 2.207 × 10−3 μm2) and dolomites (average porosity 5.26%, average permeability 1.910 × 10−3 μm2) have better exploration potential than shales (average porosity 2.46%, average permeability 0.937 × 10−3 μm2). Considering Ro distribution, the slope zones are more favorable than Kongdian Structure Belt laterally and the lower intervals of the Ek2 shale are more potential for shale oil accumulation than the upper interval vertically.