Organic Shale Research Articles

Modified approach to estimate effective porosity using density and neutron logging data in conventional and unconventional reservoirs

Porosity is a critical petrophysical parameter that governs storage capacity in reservoirs. Despite the introduction of various techniques to assess pore structure, the complexity of rock components and the wide range of pore types have led to limitations in accurately evaluating porosity, particularly in clay-dominant reservoirs. Discrepancies and inconsistencies remain among different analytical calculation methods. Determining porosity using neutron and density logs is especially challenging in the presence of clay minerals and hydrocarbon saturation, particularly gas. Gas saturation reduces rock density, while in clay-dominant formations, neutron logs often indicate excessively high porosity due to the water content in clays. The impact of clay-bound water on rock porosity is still not fully accounted for. This study proposes a modified method for estimating porosity in both conventional and unconventional reservoirs, addressing the effect of clay-bound water on porosity calculations. The proposed method incorporates the rock's composition through its response observed in the neutron and density logs. Analytical equations are formulated to account for the influence of clay-bound water on these logs, and porosity is estimated. To validate the methodology, it was applied to two wells in organic shale reservoirs and one well in a conventional reservoir. The proposed porosity estimation method produced results that closely aligned with previously established methods, demonstrating consistency across all three wells with minimal deviations. This method offers broad applicability for exploration and exploitation in both conventional and unconventional reservoirs.

Evolution of mechanical properties of organic-rich shale during thermal maturation

Accurate assessment of the mechanical properties of organic matter, clay matrix, and bulk shale during maturation remains a challenge. Here, we aim to assess the mechanical properties of organic-rich shale during maturation using a combination of nanoindentation methods and various geochemical analyses, i.e., mineral composition, mass loss rate, chemical structure of organic matter, and Rock-Eval analyses. Results show that the evolution of mechanical properties of organic matter in shale during maturation can be divided into: the main oil-generation stage, and the condensate oil and gas generation stage. The stiffening of organic matter in the shale is mainly due to increased aromaticity and condensation of aromatic groups. The clay matrix experiences a slight decrease in hardness and Young’s modulus at low maturity levels due to the generation of liquid hydrocarbons. However, overall, the clay matrix becomes stiffer as the shale matures due to shale dehydration, expulsion or cracking of liquid hydrocarbons, transformation of clay minerals, and hardening of organic matter. The Young’s modulus and hardness of bulk shale generally increase with increasing maturity. This is closely related to the hardening of organic matter and clay matrix, as well as the development of the more compact and dense microstructure in the shale.

Depressurization-induced production of shale gas in organic-inorganic shale nanopores: A kinetic Monte Carlo simulation

Methane gas production from unconventional reservoirs, such as shale formations, is in high demand due to the global energy needs. However, maximizing production remains challenging due to the ultra-tight porosity, heterogeneity, and complex nature of shale rocks under high pressure. To address this issue, we employ a novel kinetic Monte Carlo (kMC) simulation to investigate the molecular-level behavior of shale gas in both homogeneous and heterogeneous organic-inorganic shale nanopores. This approach not only provides accurate computations of shale gas under high pressure but also aims to uncover the mechanisms of shale gas storage at reservoir pressure and production during pressure drawdown. Our findings indicate that organic shale ultramicropores (pore width < 0.7 nm) contribute significantly to the highest storage capacity of shale gas but pose challenges for production capacity solely through depressurization. In contrast, the free gas zone is the primary source of shale gas production from mesoporous shales, which has a high recovery efficiency but a low production capacity due to less pronounced interaction effects from the shale surface. The heterogeneous nature of shale surfaces leads to asymmetric distributions of density and potential energy across pore widths, with methane molecules favoring locations near organic pore walls due to stronger attractive interactions, while inorganic pore walls facilitate shale gas migration. Interestingly, the optimal ultramicropore size yields the highest recovery efficiency of shale gas via depressurization, characterized by a transition from near-commensurate to incommensurate molecular packing between reservoir and post-drawdown pressures. Based on these detailed molecular simulations, further research is necessary to develop innovative techniques for enhancing shale gas recovery, especially in micropores.

Shale Oil Generation Conditions and Exploration Prospects of the Cretaceous Nenjiang Formation in the Changling Depression, Songliao Basin, China

Low-maturity shale oil predominates in shale oil resources. China’s onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (Ro) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S1) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part.

Surface morphologic changes and mineral transformation mechanisms after CO2-brine-rock reaction in organic matter-rich ferroan shale

Sequestrating CO2 in shale reservoirs can not only reduce CO2 emission, and enhance oil and gas recovery. Nevertheless, shale reservoirs were normally formed in reducing environments, and are abundant in Fe2+ and organic matter. Fe2+ influence the dissolution and precipitation behavior of minerals within the reservoir. Simultaneously, organic matter occupies the pore spaces within the reservoir, thereby affecting the reservoir physical properties. The CO2-brine-rock reaction experiment was carried out using organic matter-rich ferroan shale in this study. The changes in surface morphology of minerals and organic matter utilizing X-ray Diffraction localization monitoring techniques. Based on the TOUGHREACT, a quantitative analysis was conducted on the dissolution and precipitation of individual components. The results suggest that the carbonates preferentially dissolved at the early stage, resulting in a rougher surface morphology andthe formation ofcracks. During the early stage, ankerite transformed into pyrite and chlorite. As the reaction progresses, an elevation in the solution’s acidity facilitates converts chlorite to pyrite and kaolinite. After the dissolution of dolomite, calcite is the primary secondary mineral. The formation of clay minerals consumes Mg2+, resulting in minimal magnesite. The dissolution of feldspar was weaker than carbonate minerals. Dissolution of plagioclase results in the formation of dawsonite in solution. The dissolution of K-feldspar induces the transformation of smectite to illite. In addition, as the reaction solution acid escalated, the soluble mineral components in the large-particle polymer dissolved and dispersed into small-particle organic matter. The small-particle organic matter absorbs secondary minerals generated to form a cake-like polymer.

Study on the relationship between shale organic matter development and paleowater depth—A new understanding of the condensed section

Recent studies dispute the long-standing belief that highly organic-rich shales are predominantly linked to condensed section (CS) at the maximum flooding surface (MFS), proposing instead that they more commonly develop in shallow waters along basin margins. This hypothesis, however, has not been thoroughly investigated. Our study, focusing on the pivotal regions of the Longmaxi Formation and the Chang 7 Member for marine and continental shale exploration in China, integrates sequence stratigraphy with analyses of total organic carbon (TOC) and elemental geochemistry to pinpoint the environments conducive to the formation of organic-rich shales. The most organic-rich intervals, specifically the bottom of the Longmaxi Formation and the mid-to-lower Chang 73 sub-member, are located within the transgressive systems tract (TST), showing higher TOC levels in the middle to lower TST, compared to the CS of the MFS. The formation of high organic matter shale is related to warm, humid, and dysoxic shallow waters with minimal terrigenous influx and high primary productivity. We found a pronounced inverse relationship between organic matter concentration and water depth, with deeper waters promoting the decomposition and recycling of organic matter during sedimentation, thereby diminishing the TOC content. Moreover, volcanic activity also affected the organic enrichment in the Chang 7 Member. With high primary productivity, organic matter tends to accumulate in dysoxic slope zones. Consequently, high-organic content shale intervals are generally situated in shallow, dysoxic water environments, suggesting that the CS of the MFS may actually represent organic-poor intervals with limited source rock potential. The results of this study are of great significance for shale oil and gas exploration in China, and provide a new direction for the discovery of shale oil and gas sweet spots.

Sedimentary environment and major controlling factors of organic matter-rich shale from the Wufeng-Longmaxi formation in eastern Sichuan Basin, China

Sedimentary environment and major controlling factors of organic matter-rich shale from the Wufeng-Longmaxi formation in eastern Sichuan Basin, China

Shale pore characteristics and their impact on the gas-bearing properties of the Longmaxi Formation in the Luzhou area

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

An investigation on the pyrolysis of low-maturity organic shale by different high temperature fluids heating

This study evaluates the potential of oil and gas generation from thermal pyrolysis of low-maturity organic rich shales by high temperature fluids injection. This method aims to convert the solid organic matter into hydrocarbons, thereby enhancing the quality of shale oil. The effectiveness of this technique hinges on its ability to convert retained heavy compounds and kerogen into light, moveable hydrocarbons, while also improving the oil recovery factor. Our experimental findings reveal that the decrease of total organic carbon content predominantly occurs between 400–550 °C or even higher. Different heating fluid media were tested for their pyrolysis effectiveness, among the heating media tested, CO2 and steam mixture proved the most productive. A comparison of CO2, steam and CO2-steam pyrolysis experiments were carried out. It is observed that the oil yield is the lowest in a pure CO2 atmosphere, while oil yield from the mixture of CO2-steam pyrolysis is the highest. In addition, the pore structure and mechanical properties of shales during pyrolysis process are examined.This investigation provides a theoretical basis for the large-scale upgrading of organic-rich shale formations, highlighting the critical influencing factors of thermal pyrolysis in optimizing shale oil recovery and quality.

The role of water bridge on gas adsorption and transportation mechanisms in organic shale

This work introduces and discusses the impacts of the water bridge on gas adsorption and diffusion behaviors in a shale gas-bearing formation. The density distribution of the water bridge has been analyzed in micropores and meso-slit by molecular dynamics. Na+ and Cl− have been introduced into the system to mimic a practical encroachment environment and compared with pure water to probe the deviation in water bridge distribution. Additionally, practical subsurface scenarios, including pressure and temperature, are examined to reveal the effects on gas adsorption and diffusion properties, determining the shale gas transportation in realistic shale formation. The outcomes suggest carbon dioxide (CO2) usually has higher adsorption than methane (CH4) with a water bridge. Increasing temperature hinders gas adsorption, density distribution decreases in all directions. Increasing pressure facilitates gas adsorption, particularly as a bulk phase in the meso-slit, whereas it restricts gas diffusion by enhancing the interaction strength between gas and shale. Furthermore, ions make the water bridge distributes more unity and shifts to the slit center, impeding gas adsorption onto shale while encouraging gas diffusion. This study provides updated guidelines for gas adsorption and transportation characteristics and supports the fundamental understanding of industrial shale gas exploration and transportation.

Scale translation yields insights into gas adsorption under nanoconfinement

This work describes a scale-translating simulation framework to investigate gas adsorption behavior in nanoconfined pores. The framework combines molecular simulations (MSs), equation of state (EoS), and lattice Boltzmann (LB) simulations. MSs reveal the physics of methane adsorption in nano-sized pores, where input values of fugacity coefficients are optimized based on EoS predictions. Then, an LB free-energy model, which incorporates a viral EoS, upscales intermolecular forces and estimates adsorption behavior via a proposed fluid–wall interaction model. Armed with the values of the LB interaction parameter as a function of pressure, the LB model is used to predict fluid behavior in irregular nanopores, and the results are validated against reference MS data. The LB model is then used to study adsorption behavior at a continuum scale in representative organic shale nanopores based on finely characterized Vaca Muerta shale samples. The results show that methane adsorption could significantly increase contained fluids by 10%–25% in pores smaller than 20 nm. However, in larger pores (40 nm to 90 nm), adsorption's impact diminishes to 2%–3%, suggesting sorption's negligible role beyond a 40 nm pore size.

Oil shale enrichment mechanisms in the Lower Cretaceous Jiufotang Formation from the Ludong sag, Songliao Basin, Northeast China

In order to investigate the oil shale enrichment mechanisms and the relationship among gravity flows, volcanism, and oil shale deposition, detailed petrological, sedimentological, and organic geochemical research have been carried out on the Lower Cretaceous Jiufotang Formation in the Ludong sag, Songliao Basin, Northeast China. Seven facies were recognized and were grouped into three facies associations, namely hyperpycnites and intrabasinal turbidites, delta, and lacustrine facies associations. During the deposition of the lower Jiufotang Formation, hyperpycnites were developed during catastrophic flooding events that caused an abrupt increase in the discharge of water and sediment into the deep lacustrine environments, and a delta persisted during normal river discharge intervals and prograded into lacustrine environments. During the deposition of the upper Jiufotang Formation, deep lacustrine facies further expanded, and the extent of hyperpycnites decreased. Four types of oil shales were recognized in the Ludong sag of which those in the lower and upper Jiufotang Formation were defined as medium-to good-quality and good-to best-quality source rocks, respectively, exerting an overall thermal maturity of early oil generation. The lacustrine redox conditions show oxic to dysoxic conditions in the lower Jiufotang Formation, and anoxic to dysoxic conditions in the upper Jiufotang Formation. Oil shales were poorly-developed in the lower Jiufotang Formation and were well-developed in the upper Jiufotang Formation. During the active rift stage of the lower Jiufotang Formation, frequent occurrences of gravity flows and water-carried re-sedimentation of tuffaceous materials were unfavorable for oil shale accumulation. During the waning rift phases of the upper Jiufotang Formation, minor wind-transport of volcanic ash input into the deep lacustrine environments fertilized the lake water and supported algae blooms, leading to reduced oxygen concentrations in the bottom lacustrine waters along with high bioproductivity that were favorable for organic matter preservation and oil shale formation.

Geochemical Characteristics of Mature to High-Maturity Shale Resources, Occurrence State of Shale Oil, and Sweet Spot Evaluation in the Qingshankou Formation, Gulong Sag, Songliao Basin

The exploration of continental shale oil in China has made a breakthrough in many basins, but the pure shale type has only been found in the Qingshankou Formation, Gulong Sag, Songliao Basin, and the evaluation of shale oil occurrence and sweet spot faces great challenges. Using information about the total organic carbon (TOC), Rock-Eval pyrolysis, vitrinite reflectance (Ro), kerogen elemental composition, carbon isotopes, gas chromatography (GC), bitumen extraction, and component separation, this paper systematically studies the organic geochemical characteristics and shale oil occurrence at the Qingshankou Formation. The G1 well, which was cored through the entire section of the Qingshankou Formation in the Gulong Sag, was the object of this study. On this basis, the favorable sweet spots for shale oil exploration are predicted. It is concluded that the shale of the Qingshankou Formation has high organic heterogeneity in terms of organic matter features. The TOC content of the source rocks in the Qingshankou Formation is enhanced with the increase in the burial depth, and the corresponding organic matter types gradually changed from Ⅱ2 and Ⅱ1 types to the Ⅰ type. The distribution of Ro ranges from 1.09% to 1.67%, and it is the mature to high-mature evolution stage that generates a large amount of normal crude oil and gas condensate. The high-quality source rocks of good to excellent grade are mainly distributed in the Qing 1 member and the lower part of the Qing 2 member. After the recovery of light hydrocarbons and the correction of pyrolytic heavy soluble hydrocarbons, it is concluded that the occurrence state of shale oil in the Qingshankou Formation is mainly the free-state form, with an average value of 6.9 mg/g, and there is four times as much free oil as adsorbed oil. The oil saturation index (OSI), mobile hydrocarbon content, Ro, and TOC were selected to establish the geochemical evaluation criteria for shale oil sweet spots in the Qingshankou Formation. The evaluation results show that interval 3 and interval 5 of the Qingshankou Formation in the G1 well are the most favorable sections for shale oil exploration.

Biomarker characteristics of organic shale beds of Alam El Bueib Formation in Tut Oil Field, Shushan Basin, North western Desert, Egypt: Insights from oil/source rock correlation

Biomarker characteristics of organic shale beds of Alam El Bueib Formation in Tut Oil Field, Shushan Basin, North western Desert, Egypt: Insights from oil/source rock correlation

Evolution of fractal characteristics in shales with increasing thermal maturity: Evidence from neutron scattering, N2 physisorption, and FE-SEM imaging

Fractal dimension analysis has become an essential tool to assess the pore structure of various porous geomaterials including shale rock. In this regard, changes of fractal dimension during the thermal maturation of organic rich shale could represent the evolution of its pore structure. To this end, complementary tests were conducted on six organic rich shale samples that are in a wide range of thermal maturity (equivalent Ro values of 0.52–3.53 %). Fractal dimensions were obtained from small-angle neutron scattering (SANS), N2 physisorption, and field emission-scanning electron microscopy (FE-SEM) data. Herein, surface fractal dimensions were calculated from the N2 adsorption isotherms using the Frenkel–Halsey–Hill method, which was found between 2.46 and 2.71. Power-law exponents (E) of the SANS profiles varied from 2.75 to 3.48, indicating that both surface fractals and mass fractals would characterize the shale samples. As thermal maturity progressed, the fractal dimension shifted from surface to mass fractal while further analyses suggested this was caused by changes in the number density of pores (NDP) of various pore-size ranges. Ultimately, the pore size of the samples during such transition decreased with the increase of Ro.

Silurian to early Devonian overmature hot shales in Eastern Taurus: Source rock characteristics and links to North African petroleum systems

The study area is located in the Eastern Taurus region and is characterized by the Paleozoic autochthonous Geyik Dağı Unit (GDU) in the northern Paleo-Tethys back-arc basin. The Eastern Taurus encompasses Silurian-Early Devonian units, which may have the characteristics to be called hot shales. In the study area, the Silurian black and organic lean shales and Orthoceras-bearing limestone and shale alternation have directly deposited on the Late Ordovician (Hirnantian) peri-glacial clastics. However, while Hot shale-I unit was deposited over the ice cover rebound-related paleo-depression areas in the southern Paleo-Tethys (North Africa) during the early Silurian (Rhuddanian- Early Telychian), turbiditic black lydite successions were deposited due to the radiolarian bloom in the northern Paleo-Tethys (Taurus Belt). Therefore, the studied black shales overlying the lydite successions correspond to the late Telychian hot shale II (Sheinwoodian and Pridoli- Lochkovian), which has only been defined in the Moroccan basins. On the other hand, both lydite occurrence and late Telychian-Sheinwoodian, and Pridoli-Lochkovian black shales (equivalents of Akakus and/or Tadrart formations) indicate that the Taurus basin under distinct paleoclimate conditions witnessed different bathymetry and nutrients source (e.g., silica). In addition, pyrolysis results indicate that the studied black shales belonging to GDU have lost 85–98% of their HC potential due to the overburden resulted from the allochthonous units. However, isotopic composition of the oils from the Adana basin and from the surface seepage samples show that these oils were expelled from Devonian shales. According to the pyrolysis and isotope data, we suggest that there may be a Pridoli-Lochkovian source rock unit in the Eastern Taurus, unlike the North Africa basins (except for Tadla basin). These data indicate that the basins developed over the Silurian-Early Devonian succession, which are believed not to have been affected by the nappe events, could have yielded an economic petroleum system over the onshore and/or offshore of eastern Mediterranean basins.

Guest Editorial: Are We “Refracturing” or “Recompleting” with Mechanically Isolated Subsequent Stimulations in Organic Shales?

Numerous articles and technical papers have shown that perforating and fracture stimulating previously undrained rock in wide-cluster-spaced legacy organic shale wellbores can result in superior economics to new wells in many areas. With advances in mechanical isolation operators can seal off the narrow existing drainage intervals in legacy wells to enable stimulations to focus on “new rock.” In one reservoir-pressure-monitoring pilot well drilled by ConocoPhillips in 2016 it was observed that 85% of the lateral interval was not being drained where the original completion had 50-ft cluster spacing. The observation well was 70 ft away from the producing parent well. For wells that have relatively wide well spacings (over 600 ft), the post-stimulation total enhanced ultimate recovery (EUR) can be from three to four times the original EUR. The two most active operators doing these types of stimulations in the Eagle Ford Shale (ConocoPhillips and Devon) are primarily doing protective treatments in parent wells to avoid significant child well EUR losses from asymmetric fractures. In URTeC 3724057, Barba et al. demonstrated that when parent wells are restimulated following mechanical isolation the combined NPV10 of the post-stimulation production from the parent and the EUR preservation from the children is significantly higher than a new well’s NPV10. The first-order child wells will have asymmetric fracs running home toward the parents and stranding 40% of the reserves on their distal side if a protective refrac is not done on the parent, as was shown in SPE 213075. The second-order child wells have an average of a 20% EUR loss. Discussions with operators and presentations by upper management concerning this damage indicate that other than a few of the main players doing these subsequent stimulations, not all operators are aware of the detrimental effects of asymmetric fractures. A major operator presenting at the 2023 SUPER DUG Conference mentioned that they saw positive production increases when Bakken parent wells had fracture-driven interactions (FDIs) from offset child-well fracs. When the author asked the presenter in the Q&amp;A session if they were concerned about the EUR damage from the asymmetric fractures which resulted in these FDIs, he was clearly not aware that it was a problem. For those who might not fully grasp the nuances of challenging parent-child interactions, consider the situation of parents supporting adult children who have not yet achieved independence. The goal for these parents is to encourage self-reliance and maturity, rather than a return to a dependent lifestyle. In the context of well management, the parent-well protective refrac is also designed to enable child wells to achieve their maximum production potential. While these protective recompletions in legacy parent wells can provide a significant economic benefit, the treatments have not been accepted by all operators as a tool to significantly grow company asset value. There is little or no activity in areas where all the wells on a pad are legacy parent wells with no nearby children.

Pyrite Characteristics in Lacustrine Shale and Implications for Organic Matter Enrichment and Shale Oil: A Case Study from the Triassic Yanchang Formation in the Ordos Basin, NW China.

Pyrite is widely distributed in lacustrine shales and has become a research focus in unconventional oil and gas exploration. Pyrite morphology is useful for identifying different types of organic matter and assessing shale oil enrichment in organic-rich shale. Abundant pyrite is developed in the source rocks from the Chang 7 Member of the Yanchang Formation in the Ordos Basin, NW China. However, the relationship between different pyrite types and the differential enrichment of shale oil still needs to be clarified. The organic geochemistry, petrology, and isotopic composition of the Chang 7 Member samples were analyzed. The significance of pyrite types and sulfur isotopic compositions as indicators of depositional environments and shale oil enrichment was emphasized. The Chang 7 shales contain three pyrite morphologies, framboidal pyrite (type A), spherulitic pyrite (type B), and euhedral and anhedral pyrite (type C), and their aggregates. The sulfur isotopic compositions of pyrite (δ34Spy) in Chang 7 shales with different pyrite types exhibited regular patterns. The δ34S values of types A, B, and C pyrites were sequentially positive overall (average values are -2.739, 2.201, and 7.487‰ in sequence), indicating that type A pyrite was formed during the syn-sedimentary to early diagenetic stage and types B and C pyrites were formed during the early to middle diagenetic stage. Types A, B, and C pyrites showed sequentially increasing kerogen type index values and kerogen carbon isotope values (mean values of -31.59, -28.70, and -26.45‰, successively), indicating that the horizons where types A, B, and C pyrites developed correspond to types I, II, and III organic matter, respectively. Strong correlations between the pyrite content and oil components reveal that pyrite indicates shale oil enrichment. Moreover, variations in pyrite type significantly influenced the enrichment behavior of shale oil. Types A and B pyrites contributing to reservoir space showed shale oil enrichment. They promoted saturated hydrocarbon enrichment at >15% pyrite content, whereas type C pyrite did not indicate shale oil enrichment. These findings provide new insights into the differential enrichment of organic matter and shale oil and valuable guidance for the large-scale exploration and development of shale oil resources.

Review of bacterial sulfate reduction in lacustrine deposition and its identification in the Jimsar Sag, Junggar Basin

Bacterial sulfate reduction (BSR) is the interaction between sulfates and organic matter that bacteria participate in during the early diagenetic stage. It is one of the important biogeochemical processes that affect the formation of sulfides and sulfur cycling. Due to the lack of sulfate in the lakes, there is relatively little research on lacustrine bacterial sulfate reduction (LBSR), and related research mainly focuses on marine sedimentation. Marine incursion and volcanic ash may bring sulfate to lakes, providing a possibility for the occurrence of LBSR. The process, main influencing factors, and identification methods of BSR are summarized systematically. Through comprehensive analysis, it is believed that the occurrence depth of LBSR is relatively shallow (about 10 cm). Sulfate concentration, total organic matter, and sulfate reducing bacteria activity are the main controlling factors of BSR. The petrological and geochemical characteristics of the product are commonly used indicators to determine whether BSR occurs. The Jimsar Sag is one of the important shale oil rich areas in China. Taking Jimsar Sag as an example, the identification of LBSR was attempted. Based on the characteristics of framboidal pyrite, columnar calcite, and fine-grained dolomite, comprehensive analysis suggests that LBSR has occurred in the Lucaogou Formation of the Jimsar Sag. BSR has a significant effect on the degradation of organic matter, and TOC is usually lower in areas with higher intensity. Therefore, BSR has impact on the enrichment of organic matter in shale. The relevant research may have reference significance for the enrichment of lacustrine organic matter and shale oil exploration.

A log-based method for fine-scale evaluation of lithofacies and its applications to the Gulong shale in the Songliao Basin, Northeast China

The Gulong shale demonstrates high clay content and pronounced thin laminations, with limited vertical variability in log curves, complicating lithofacies classification. To comprehend the distribution and compositional features of lithofacies in the Gulong shale for optimal sweet spot selection and reservoir stimulation, this study introduced a lithofacies classification scheme and a log-based lithofacies evaluation method. Specifically, the ΔlgR method was utilized for accurately determining the total organic carbon (TOC) content; a multi-mineral model based on element-to-mineral content conversion coefficients was developed to enhance mineral composition prediction accuracy, and the microresistivity curve variations derived from formation micro-image (FMI) log were used to compute lamination density, offering insights into sedimentary structures. Using this method, integrating TOC content, sedimentary structures, and mineral compositions, the Qingshankou Formation is classified into four lithofacies and 12 sublithofacies, displaying 90.6% accuracy compared to core description outcomes. The classification results reveal that the northern portion of the study area exhibits more prevalent fissile felsic shales, siltstone interlayers, shell limestones, and dolomites. Vertically, the upper section primarily exhibits organic-rich felsic shale and siltstone interlayers, the middle part is characterized by moderate organic quartz-feldspathic shale and siltstone/carbonate interlayers, and the lower section predominantly features organic-rich fissile felsic/clayey felsic shales. Analyzing various sublithofacies in relation to seven petrophysical parameters, oil test production, and fracturing operation conditions indicates that the organic-rich felsic shales in the upper section and the organic-rich/clayey felsic shales in the lower section possess superior physical properties and oil content, contributing to smoother fracturing operation and enhanced production, thus emerging as dominant sublithofacies. Conversely, thin interlayers such as siltstones and limestones, while producing oil, demonstrate higher brittleness and pose great fracturing operation challenges. The methodology and insights in this study will provide a valuable guide for sweet spot identification and horizontal well-based exploitation of the Gulong shale.