Basinal Shales Research Articles

Satellite‐Based Surveys Reveal Substantial Methane Point‐Source Emissions in Major Oil & Gas Basins of North America During 2022–2023

AbstractUtilizing imaging spectroscopy technology to identify methane super‐emitters plays a vital role in mitigating methane emissions in the Oil & Gas (O&G) sector. While earlier research has uncovered significant point‐source methane emissions from O&G production in the US and Canada, which are key regions with large methane emissions, a comprehensive post‐COVID‐19 survey has been notably absent. Here, we perform a detailed survey of methane super‐emitters across multiple basins of North America (Marcellus Shale, Haynesville/Bossier Shale, Permian Basin and Montney Shale) using the new Chinese Gaofen5‐01A/02 (GF5‐01A/02) satellite measurements during 2022–2023. We detect 139 individual methane plumes emanating from 122 point sources, with flux rates ranging from 519 to 16,071 kg hr−1. These emissions exhibit a highly skewed and heavy‐tailed distribution, constituting approximately 23% of the flux inversion with TROPOMI in the sample region, with a range of 13%–40%. Moreover, we observe a 66.7% reduction in methane emissions in Permian Basin during COVID‐19, followed by fluctuations until spring 2023. By summer 2023, methane emissions rebound to twice their previous magnitude (1.68 ± 0.58 Tg a−1). Using these point‐source surveys, we further quantify a regional methane emission of 2.69 ± 0.86 Tg a−1 in Permian Basin. This estimation closely aligns with top‐down inversions (2.22 ± 0.40 Tg a−1) from TROPOMI. The upscale estimation underscores the effectiveness of high‐resolution remote sensing measurements in improving bottom‐up emissions inventories and refining regional methane emission assessments. Our results highlight the potential climate benefits derived from regular monitoring and specific remediation efforts focused on relatively few strong point‐source emissions.

A characterization study of Wadi Thamad oil shale: Towards a new source of energy in Jordan

AbstractJordan's energy sector faces significant challenges due to rising fuel prices, making the exploration of local energy resources crucial. The abundant oil shale deposits in Wadi Thamad present a promising opportunity. Since Wadi Thamad oil shale has never been studied before, this research focuses on the Wadi Thamad basin near Madaba, Jordan, aiming to comprehensively characterize its oil shale using advanced analytical techniques. Using X‐ray diffraction, Fourier transform infrared spectroscopy, X‐ray fluorescence, scanning electron microscopy, thermogravimetric analysis (TGA), and differential scanning calorimetry, this study assesses the mineralogical, chemical, and thermal properties of Wadi Thamad oil shale. The findings reveal calcite and quartz as the primary minerals, with significant aliphatic, CO2, hydroxyl, and carboxyl groups. Elemental analysis highlights essential oxides, such as CaO and SiO2. Fischer assay results indicate an oil content of 5.3–10.1 wt%, a gross‐calorific value of 4.56–7.69 MJ/kg, and a sulfur content of 1.77–2.10 wt%. The peak pyrolysis temperature is 432.4°C from TGA. This research's novelty lies in its comprehensive approach to characterizing the underexplored Wadi Thamad oil shale basin. The findings enhance the understanding of Wadi Thamad's geological composition and underscore its potential as a local energy resource, contributing valuable data to Jordan's energy portfolio and offering economic benefits.

Sedimentary dynamics and depositional model for mud accumulation in deep lake basins: A case study in the Upper Triassic Chang-7 Member, Ordos Basin, northern China

Shales in deep lake basins have become the main focus of continental shale oil and gas exploration. In order to highlight the sedimentary dynamics of mud deposition in deep lake basins, a combination of core observation, thin section examination, X-ray diffraction, and QEMSCAN (quantitative evaluation of minerals by scanning electron microscopy) was used to analyze the depositional characteristics of mudrocks in the Chang-7 Member from the Yanchang Formation (Upper Triassic) in Ordos Basin, and to establish a depositional model for mud accumulation in deep lake basins. This study recognizes four mudrock lithofacies in the Chang-7 Member: (1) the laminated silt-bearing mudstone, which generally develops a binary composition of “silt–clay” or a ternary composition of “silt–clay–organic matter”; (2) the graded mudstone, mainly composed of dark gray and gray-black mudstone sandwiched by silt-bearing mudstone; (3) the massive mudstone, internally showing a uniform distribution of quartz, clay, and carbonate minerals, with also a small amount of organic detritus; and (4) the laminated shale, which is generally composed of clay laminae, and organic laminae of the former two. Sediment supply, topographic slope, and flood intensity combine to control the evolution of gravity flows and the transport and deposition of the mudrock in the Chang-7 Member. The influence of orogeny provides terrain gradient, water depth, abundant sediments at source areas, and triggering mechanism for the formation of gravity flows. Floods triggered by wetting events provide the impetus for sediment transport. Mud deposition in the Chang-7 Member was mainly related to the transport and sedimentation of mud by hyperpycnal flows and rapid sedimentation by buoyant plume flocculation. A comprehensive evolutionary model for shale accumulation in the deep lake basin is established by integrating various triggering mechanisms and mud transport sedimentary processes.

Geologic characteristics, exploration and production progress of shale oil and gas in the United States: An overview

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle–Late Devonian, Early Carboniferous (Middle–Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian–Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and “shale reservoirs” are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×1012 t and 290×1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the “shale revolution”, the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007–2023, shale oil and gas production in the United States increased from approximately 11.2×104 tons of oil equivalent per day (toe/d) to over 300.0×104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Constraining faults and stratigraphic zones in shale and tight oil basins via 3D geocellular models

The validity of regional and basin-wide geomodels for unconventional and tight-oil plays depends on the accuracy and precision of the available structural and stratigraphic frameworks. Integrated reservoir models, combining seismic, log, core, and production data, are critical tools necessary for capturing the complexity of basin fill history and for understanding the 3D facies architecture. For researchers, a lack of publicly available 3D seismic surveys, even in basins with a high density of wells, is an impediment to creating accurate models of faults and stratigraphic zones. Three approaches were used to overcome this deficit: 1) well log correlation of detailed stratigraphic zones using densely spaced vertical wells; 2) calculation of trend surfaces from thousands of geosteered 3D horizontal well position logs; and 3) residual analysis of regional and local horizontal well trend surfaces to identify faults. Independent data were used in this work to confirm the validity of these new surfaces and faults, including 3D seismic interpretations (where available), well log-based fault correlations, and analysis of seismicity. The resulting horizons were used to increase the accuracy and precision of the structure and stratigraphy input for the 3D geocellular models. Examples of the approaches to refining geomodels are illustrated for the main North American unconventional reservoir and tight oil plays, including the Bakken, Barnett, Eagle Ford, Fayetteville, Haynesville, Marcellus, and the Midland and Delaware Basins. The horizontal well trend analysis techniques and workflows in this study will aid researchers attempting to build large, regional geocellular models for unconventional plays in improving the accuracy and precision of their 3D geocellular models through the improved constraint of faults and stratigraphic zones.

The Inversion Method of Shale Gas Effective Fracture Network Volume Based on Flow Back Data—A Case Study of Southern Sichuan Basin Shale

Fracture network fracturing is pivotal for achieving the economical and efficient development of shale gas, with the connectivity among fracture networks playing a crucial role in reservoir stimulation effectiveness. However, flow back data that reflect fracture network connectivity information are often ignored, resulting in an inaccurate prediction of the effective fracture network volume (EFNV). The accurate calculation of the EFNV has become a key and difficult issue in the field of shale fracturing. For this reason, the accurate shale gas effective fracture network volume inversion method needs to be improved. Based on the flow back characteristics of fracturing fluids, a tree-shaped fractal fracture flow back mathematical model for inversion of EFNV was established and combined with fractal theory. A genetic algorithm workflow suitable for EFNV inversion of shale gas was constructed based on the flow back data after fracturing, and the fracture wells in southern Sichuan were used as an example to carry out the EFNV inversion. The reliability of the inversion model was verified by testing production, cumulative gas production, and microseismic results. The field application showed that the inversion method proposed in this paper can obtain tree-shaped fractal fracture network structure parameters, fracture system original pressure, matrix gas breakthrough pressure, fracture compressibility coefficient, reverse imbibition index, equivalent main fracture half length, and effective initial fracture volume (EIFV). The calculated results of the model belong to the same order of magnitude as those of the HD model and Alkouh model, and the model has stronger applicability. This research has important theoretical guiding significance and field application value for improving the accuracy of the EFNV calculation.

Deep/ultra-deep shale strength criterion: A case study of southern Sichuan Basin shale

Deep/ultra-deep shale gas reservoirs are a vital area for future shale gas development, which mainly relies on the stimulation of network fracturing. In such a reservoir, engineering technologies such as wellbore stability evaluation and network fracturing design are all closely related to the shale mechanical characteristics. Currently, most studies focus on the elastic-plastic, brittle-ductile properties of shale, which are characterized based on shale strength. However, there is still a lack of in-depth research on their failure strength and strength criteria specifically for deep/ultra-deep shale. To accurately characterize shale failure strength, numerous scholars have researched shale strength criteria. Nevertheless, due to the high geo-stress of deep/ultra-deep reservoirs, shale properties tend to transition from brittle to ductile, resulting in poor fitting of classical rock strength criteria to test data under high confining stresses. This study focused on the outcrops of the Longmaxi Formation shale, and high-confining-stress triaxial compression tests were conducted to investigate the strength variation characteristics of shale. Based on the Mohr-Coulomb criterion, a power-form MC criterion was proposed by introducing a power function of confining stress as a correction term, and its reliability, sensitivity, and applicability were evaluated. The results indicate that the non-linear characteristics of the power-form MC criterion curve better match the actual situation, allowing for a more accurate prediction of shale strength under high confining stress. Furthermore, the power-form MC criterion has low sensitivity to changes in confining stresses, indicating that the required amount of test data for fitting can be appropriately reduced during application. Additionally, the power-form MC criterion is applicable to some extent to other types of high-strength rocks buried at greater depths. The results of this study contribute to understanding the strength characteristics of deep/ultra-deep shale under high confining stress, providing important references and theoretical basis for drilling, completion, and stimulation practices in deep shale gas reservoirs.

Gold in phosphorites: Accumulation forms and practical significance

Research subject. The gold-bearing potential of modern (oceanic) and ancient industrial types of phosphorite ores, including aphanitic, microgranular, granular, nodular, shell and karst. Aim. To assess the ability of phosphorites to accumulate gold to industrial concentrations. This issue has been actively discussed in the geological community in recent years due to the advent of high-precision methods for studying matter. Methods. Russian and foreign publications, unpublished geological data, as well as the authors’ data collected over a 30-year period of studying phosphorites. Results and discussion. In the section, 14 packs of rocks were identified, which are represented by 6 lithological types of secondary dolomites. Their distribution along the section, along with the presence of characteristic faunal remains, made it possible to establish three members in the section, which can be correlated with the Katian, Hirnantian, and Ruddanian stages of the General Stratigraphic Scale. Conclusion. Conditions for the possible joint accumulation of phosphates and gold are manifested in black shale basins, as well as in shelf shallow waters with glauconite-sand sediments. However, due to significant differences in the natural features of gold and phosphates, their industrial clusters are formed separately from each other. This is evidenced by the insignificant accumulation of phosphorus in the ores of gold deposits of black shale formations,as well as its low-quality concentrations in industrial phosphorite beds of phosphorite-bearing basins. For gold, phosphorites are only temporary collectors, the productivity of which depends on the combination of many, frequently random and slightly related factors.

Authigenic Carbonate Burial Within the Late Devonian Western Canada Sedimentary Basin and Its Impact on the Global Carbon Cycle

AbstractStable carbon isotope ratios (δ13C values) of marine carbonates are widely used to infer the relative burial rates of organic carbon, a source of oxygen to the ocean‐atmosphere system. This inference, however, is based on the assumption that ocean‐atmospheric carbon is buried either as organic carbon or as marine carbonate minerals. The burial of authigenic carbonate minerals formed within sediments after deposition, with low δ13C values (i.e., similar to organic carbon), has been proposed to explain high δ13C values in marine carbonates without the need for high burial fluxes of organic carbon. To test this hypothesis, we focus on the Late Devonian, a time period with both pervasive ocean anoxia and a severe reduction in shallow‐water carbonate deposition—conditions hypothesized to promote authigenic carbonate formation. We present sedimentological and geochemical data from limestones and black shales of the Wabamun Group, Besa River and Exshaw formations of the Western Canada Sedimentary Basin. These data are compared to inorganic and organic weight percent measurements of North American shales acquired from the USGS National Geochemical Database (N = 4,437). Results show that basinal shale lack authigenic carbonate with low δ13C values and that the mean δ13C value of carbonate in these shales (−0.3‰) do not differ substantially from mean δ13C of carbonates in platform carbonates of a similar age (0.6‰). Furthermore, inorganic carbon content in Late Devonian shales (mean weight percent = 0.55%, N = 54) is lower than average Phanerozoic North American shale (mean of 1.95%, N = 4,055). Lastly, organic carbon‐to‐inorganic carbon ratios (OC:IC) of North American shales are well above 1 (mean = 3.72 for Late Devonian shales (N = 374), 2.25 for shales (N = 3,653) of all other ages). Therefore, even if the burial of fine‐grained siliciclastic formations carrying authigenic carbonates were to increase, the concomitant increase in organic carbon burial would be even larger. Together, data from this study do not provide evidence that the burial of authigenic carbonate would have a significant effect on global carbon isotope mass balance.

Early Cretaceous climatic influences on organic matter enrichment in lacustrine shales: Insights from the Liupanshan Basin of northwestern China

Organic-rich petroleum source rocks are widespread in Early Cretaceous strata, but the related paleoclimatic conditions are still uncertain. Aptian-Albian lacustrine sediments from the Liwaxia and Madongshan formations in the Liupanshan Basin of northwestern China provide vital material to reveal correlations between the Early Cretaceous paleoclimate and the formation of organic-rich lacustrine shales. Outcrop samples were analyzed for total organic carbon (TOC), C/N ratio, CaCO3 content, lipid biomarkers, and compound-specific n-alkane carbon isotopes. Results show that organic matter (OM) of the Liwaxia Formation was mainly sourced from lacustrine plankton and deposited in a weakly stratified and suboxic water column under a hot and arid climate. Organic matter in the lower part of the Madongshan Formation was derived from a mixture of aquatic organisms and higher plants under a warm and humid climate; plant carbon sources were widely available, and the water column was strongly saline, stratified, and anoxic. Elevated temperatures and a less humid climate accompanied the deposition of the upper part of the Madongshan Formation. Higher plants were the primary OM source, and the carbon source became limited. The water column was hypersaline and stratified, and the bottom water was less anoxic. Abrupt changes in the OM inputs and depositional environments documented in the Madongshan Formation were ascribed to global climatic variations. A warm and humid climate during the Aptian-Albian transition enhances continental nutrient inputs and promotes the formation of reduced water conditions, which directly controls the formation of the coeval organic-rich shales in lacustrine basins in China.

Semi-Analytical Reservoir Modeling of Non-Linear Gas Diffusion with Gas Desorption Applied to the Horn River Basin Shale Gas Play, British Columbia (Canada)

Adsorbed gas may account for a significant part of the gas resources in shale gas and coalbed methane plays. Understanding gas sorption behaviors and integrating gas desorption into analytical reservoir modeling and an associated transient performance analysis are important for evaluating a system’s gas desorption ability and further analyzing its CO2 injectability, utilization, and storage capacity. However, gas desorption, along with other pressure-dominated gas properties, increases a system’s non-linearity in theoretical studies. Few studies on analytical modeling have integrated the gas desorption feature into a non-linear system and validated the model’s accuracy. In this study, the desorbed gas due to pressure decay was treated as an additional source/sink term in the source-and-sink function methods. This method was combined with the integral image method in a semi-analytical manner to determine the amount of gas desorption. Fundamental reservoir and gas properties from the Horn River Basin shale gas play were chosen to evaluate the methodology and the performance of the associated production well. The results were compared with the commercial fine-gridding numerical simulation software, and good matches were achieved. The results showed that the desorbed gas released from rock will supply free-gas flow when the pressure significantly decreases due to gas production. The production wellbore pressure can be maintained at a higher level, and the production rate was higher than in cases where gas desorption was not considered, depending on the operating conditions.

Salinization of groundwater in shale gas extraction area in the Sichuan Basin, China: Implications for water protection in shale regions with well-developed faults

The expanding growth of shale gas development has sparked global concern over water-related environmental issues. However, research on groundwater contamination in shale gas areas in China remains limited, impeding environmentally friendly industry practices. To address this gap, we investigated the Wufeng-Longmaxi shale region in the Sichuan Basin, encompassing both operational and prospective shale gas extraction sites, to assess the effects of shale gas operations on shallow groundwater quality. We found there was no significant correlation between groundwater quality and the minimum distance from the shale gas well pads, and some groundwater samples located far from shale gas well pads, rather than those close to pads, were salinized. These findings suggest minimal impacts from shale gas drilling and hydraulic fracturing. The salinized groundwater samples are characterized by high salinity levels and ion concentrations, and are located near fault zones. The primary source of shallow groundwater salinization was derived from the Triassic formation brines confirmed through the assessment of the sensitivity and conservative mixing models. Faults in the study area were identified as pathways for the upward migration of Triassic brines, evidenced by the proximity of salinized samples to fault zones. However, further investigation is required to ascertain whether shale gas extraction activities have induced the migration of formation brines. The occurrence and reactivation of faults, induced by microseismic activities, may pose an increased risk of groundwater contamination in tectonically complex fault zones during shale gas extraction. Therefore, it is imperative to enhance extraction strategies and technologies, particularly in shale regions with well-developed faults, such as optimizing well placement regulation, controlling hydraulic fracturing scale, and strengthening environmental monitoring. By shedding light on potential environmental ramifications of shale gas extraction, especially in fault-rich regions, our study informs water protection strategies and the sustainable advancement of the shale gas industry.

Potential for CO2 storage in shale basins in China

China is the second largest shale gas and oil producing country possessing large and significant shale basins, and it is also one of the top carbon emitting countries. Therefore, there is significant potential to store CO2 in shales in China to remove the carbon emission and enhance and gas recovery simultaneously. This research provides a comprehensive prediction of potentials of CO2 storage in major shale gas/oil basins in China based on most recent publications where density variation of CO2 at different subsurface conditions is considered and the different stages of development are classified. We optimise the calculation equations for shale gas and oil respectively, and further classified the three tiers (i.e. commercial, potential and possible reservoirs) in the calculation to prioritise the sequestration site selection. A total of around 6194 Gt, CO2 sequestration in shales, including 172 Gt for commercial, 849 Gt for potential and 5147 Gt for possible storage, equivalent to a total of 620 years’ carbon emissions in China is expected. These can be realised in around 20 years, 20–50 years and 50–100 years respectively. For future applications, more concerns should be on the evaluation criteria of sequestration sites in shales, CO2 fracturing mechanisms and potential leakage, multi-phase seepage and reactions, and environmental monitoring systems. As a comprehensive assessment of potentials of CO2 storage in shale basins in China, this paper will provide an important guide for future academic studies, industrial operations and government policy making.

Optimizing CO2 Injection Strategies: A Deep Learning Approach to Prediction of CO2 phase across Seven Shale Basins

Optimizing CO2 Injection Strategies: A Deep Learning Approach to Prediction of CO2 phase across Seven Shale Basins

A numerical study of complex fractures propagation path in naturally fractured gas shale: Reorientation, deflection and convergence

Shale gas reservoir is characterized as the naturally fractured formation, which is benefit for complex hydraulic fracture network generation. The propagation path is crucial to determine the reservoir stimulation result, and evaluate the quality of complex hydraulic fracture network. To investigate the propagation path of complex hydraulic fracture in gas shale, the hybrid combined discrete fracture network-finite element method (DFN-FEM) model is involved. Combining a linear hardening and a non-linear softening process, a non-linear traction-separation law is proposed to describe the fracture damage evolution. Validated with open-reported laboratory experiments, the hydraulic-natural fracture (HF–NF) interaction criterion is depicted under four geomechanical and injection factors. Based on a field-scale model of Sichuan basin shale gas reservoir, the complex hydraulic fractures propagation process is simulated with rock deformation and stress shadow. Several propagation path indexes are defined with fracture morphology to discuss the effect of representative geomechanical, injection and multi-clustering parameters. The results show that the tension fractures are predominant to hydraulic fractures propagation path and shear the natural fractures, due to the combined influence of natural fractures network and interference between clusters. The horizontal stress contrast and the injection fluid viscosity is governing to the propagation path and morphology, rather than the friction coefficient and injection rate. Multi-clustered hydraulic fractures converge into a dominant fracture due to the attraction with a short clusters-spacing, while the exclusion is observed along the propagation path with the increase of clusters number.

Source characterization of volatile organic compounds at Carlsbad Caverns National Park

ABSTRACT Carlsbad Caverns National Park (CAVE), located in southeastern New Mexico, experiences elevated ground-level ozone (O3) exceeding the National Ambient Air Quality Standard (NAAQS) of 70 ppbv. It is situated adjacent to the Permian Basin, one of the largest oil and gas (O&G) producing regions in the US. In 2019, the Carlsbad Caverns Air Quality Study (CarCavAQS) was conducted to examine impacts of different sources on ozone precursors, including nitrogen oxides (NOx) and volatile organic compounds (VOCs). Here, we use positive matrix factorization (PMF) analysis of speciated VOCs to characterize VOC sources at CAVE during the study. Seven factors were identified. Three factors composed largely of alkanes and aromatics with different lifetimes were attributed to O&G development and production activities. VOCs in these factors were typical of those emitted by O&G operations. Associated residence time analyses (RTA) indicated their contributions increased in the park during periods of transport from the Permian Basin. These O&G factors were the largest contributor to VOC reactivity with hydroxyl radicals (62%). Two PMF factors were rich in photochemically generated secondary VOCs; one factor contained species with shorter atmospheric lifetimes and one with species with longer lifetimes. RTA of the secondary factors suggested impacts of O&G emissions from regions farther upwind, such as Eagle Ford Shale and Barnett Shale formations. The last two factors were attributed to alkenes likely emitted from vehicles or other combustion sources in the Permian Basin and regional background VOCs, respectively. Implications: Carlsbad Caverns National Park experiences ground-level ozone exceeding the National Ambient Air Quality Standard. Volatile organic compounds are critical precursors to ozone formation. Measurements in the Park identify oil and gas production and development activities as the major contributors to volatile organic compounds. Emissions from the adjacent Permian Basin contributed to increases in primary species that enhanced local ozone formation. Observations of photochemically generated compounds indicate that ozone was also transported from shale formations and basins farther upwind. Therefore, emission reductions of volatile organic compounds from oil and gas activities are important for mitigating elevated O3 in the region.

Improved prediction of shale gas productivity in the Marcellus shale using geostatistically generated well-log data and ensemble machine learning

This study proposes the application of geostatistically generated well-log data to predict well productivity in Marcellus shale reservoirs using ensemble machine learning (ESM). ESM was voting weighted by four individual machine learning methods: random forest (RF), gradient boosting, extreme gradient boosting, and light gradient boosting. The ESM model was trained based on 9921 wells that are qualified as training data. The well-log data had to be predicted using ordinary kriging for all 9921 wells because there were only 18 wells with well-log data for gamma-ray, resistivity, and density. Three cases were compared to analyze the influence of well-log data on machine learning performance. Case 1 comprised only basic well information, such as well location and fracturing-related parameters. Case 2 included the data from Case 1, and the well-log data of the closest well among the 18 wells were assigned to 9921 wells. In Case 3, to data of Case 1, the kriging-generated well-log data were added. In conclusion, Case 3 yielded the best performance among the machine learning algorithms, the highest coefficients of determination, and the lowest mean square errors. According to the RF models, the feature importance of the well-log data in Case 3 was double that in Case 2. The geostatistical method allowed us to make good use of the well-log data despite the restricted number of wells with the well-log compared to the enormous scale of the Marcellus shale. Moreover, basic well information is affordable compared to costly data such as permeability and porosity, even before the production start point. Thus, it can be applied to guide decision-makers when determining a drilling target. Furthermore, owing to its versatility in data affordability, the proposed method could be expanded to other shale basins, such as Barnett, Eagle Ford, and Scoop.

Application of Organic Petrology and Raman Spectroscopy in Thermal Maturity Determination of the Karoo Basin (RSA) Shale Samples

An assessment performed using raman spectroscopy has found space in the black shales of the Cisuralian-age rocks of the Karoo Basin in South Africa, particularly those from the Guadalupian Ripon, Cisuralian Whitehill and Prince Albert Formations. It is used in conjunction with geochemical screening techniques such as organic petrology and programmed pyrolysis. In turn, the combination of these techniques is used for the assessment of the thermal maturity of the sedimentary organic matter from the perspective of hydrocarbon generation, retention, and expulsion. To provide further understanding of the black shales in the Cisuralian-age rocks of the Karoo Basin in South Africa, this study focuses on the characterization of samples from the KWV−01 borehole drilled in the southeastern Karoo Basin. In addition, the USA Devonian/Carboniferous Berea Sandstone project samples were included for comparison, and were used as a quality assurance measure. Organic petrology was utilized to assess the organic quality and thermal maturity of the black shales. The results obtained showed that the Karoo Basin shales are overmature, containing an abundance of solid bitumen, and this often characterizes a shale reservoir with moveable hydrocarbons (shale gas). The programmed pyrolysis analysis conducted on the black shales of the Karoo Basin yielded artifact results, as they were determined from a very low and poorly defined S2 peak. This indicated the shales to be overmature and categorized them to be of poor hydrocarbon generation potential. Raman spectroscopy was used to gain insights about the molecular structure of the black shales and to assess if this technique could be used as a complimentary tool to determine the thermal maturity of the shale samples. Raman parameters such as G–D1 Band separation, G and D1 band full width at half maximum (Gfwhm and D1fwhm) and G band position were successfully correlated with vitrinite reflectance (RoV), demonstrating a good potential for Raman spectroscopy to predict the thermal maturity of the shales. Overall, the study provides valuable information and knowledge concerning black shale sample characterization (particularly the thermal maturity and molecular structural characterization) in the Karoo Basin, South Africa.

Guest Editorial: Brownfield Optimization The Key To Unlocking Sustainable Oil and Gas?

The topic of sustainability within the oil and gas industry has dominated news agendas in recent years. As ‘Net Zero by 2050’ goals loom closer, the sector is under greater pressure than ever to decarbonize operations and source oil and gas via more sustainable methods. With the energy transition continuing at pace, the growth of renewable energy has been exponential. Energy sources such as nuclear and wind are set to account for a greater portion of the energy mix. Renewables expenditure is also expected to double over the next 10 years to more than $1,300 billion per year, and grid expenditure is likely to exceed $1,000 billion per year in 2030. However, oil and gas will undoubtedly play a crucial role in meeting global energy demand for the foreseeable future. A recent industry report highlighted that conventional hydrocarbons are set to comprise 49% of the energy mix in 2050, emphasizing the sustained requirement for traditional hydrocarbons. It is no secret the oil and gas sector is a high producer of carbon emissions, and according to the International Energy Agency, global production, transportation, and processing of oil and gas emitted the equivalent of 5.1 billion tons of CO2 in 2022. That’s almost 15% of total energy-related greenhouse gas emissions. So, how do we as an industry continue to extract this much needed energy source in a more-sustainable manner? Methods to curb this emission are already in practice, with operators utilizing new technology to reduce waste-gas production, return the gas to on-site product streams, and reinject methane into reservoirs. A notable example came from ExxonMobil in January of this year with the company announcing it had stopped routine flaring of natural gas from production in the top US shale basin, using compressors to push natural gas to a pipeline. It has also allocated $17 billion through 2027 to lower its greenhouse gas emissions globally. Electrification is also a hot topic, with operators investigating methodologies for how to reduce emissions from offshore assets. bp, Equinor, and Ithaca Energy recently signed a memorandum of understanding to explore electrification options for their offshore production facilities in the West of Shetland area in the North Sea. Electrification solutions could include power from shore, potentially from onshore wind, or from offshore wind. Full electrification would require in the region of 200 MW of power. If successful, the fields would become the first oil and gas developments on the UK Continental Shelf to be powered by electricity delivering a fully renewable solution. These latest industry moves are bold. They certainly show that much-needed action is now taking place and that industry is responding to social and environmental pressures to make changes.

The pattern of organic matter type occurrence and distribution in predicting hydrocarbon source formation: an example from Eocene Niger Delta Basin shale deposits

The pattern of organic matter type occurrence and distribution in predicting hydrocarbon source formation: an example from Eocene Niger Delta Basin shale deposits