Shale Gas Prospects Research Articles

A transfer learning framework for the assessment of unconventional resources opportunities in the Middle East

An inadequate understanding of fluid transport processes in ultra-low permeability rocks has propelled data-driven modeling as an alternative and complementary tool to create recovery forecasts that honor the available data in the field. However, newly discovered fields lack data, which makes it challenging to apply traditional data-driven approaches to decision-making. Transfer learning provides an opportunity to start the early-stage analysis of the asset before adequate data becomes available. Here, we present a transfer learning framework that allows the basin-wide assessment of new shale gas and tight oil prospects. The proposed method is developed on real-world data from several thousand horizontal hydraulically fractured wells in the Eagle Ford super-basin in South Texas. A novel aspect of our method is integrating reservoir engineering domain expertise and the relationship among geologic and petrophysical variables, drilling and completion parameters, and well productivity in the data pre-processing and feature generation steps. We consider the temporal and spatial balancing of the training data to ensure that the resulting predictive models honor the real-world practices followed during unconventional field development. Our full-cycle transfer learning workflow consists of dimensionality reduction and unsupervised clustering, supervised learning, and hyperparameter fine-tuning. We test the workflow by examining the performance of a data-driven model of the Eagle Ford Basin on potential plays in the Middle East: Tuwaiq Mountain and Hanifa. The existence of multiple types of hydrocarbons–liquid oil, condensate, and dry gas–in the Eagle Ford results in a model flexible enough to be tested on various types of assets in a new location. We address the challenge of model overfitting by using data types with a relatively low resolution, which allows generalization to different geologies with basin-wide accuracy.

Unconventional hydrocarbon prospectivity of the Paleoproterozoic Fraynes Formation in Manbulloo S1, Northern Territory

The Paleoproterozoic Fraynes Formation in the Birrindudu Basin is a chronostratigraphic equivalent to the prospective Barney Creek Formation in the McArthur Basin and yet a comparable understanding of its source potential is lacking. As part of Geoscience Australia’s Exploring for the Future program, this study aims to assess the hydrocarbon generating potential and shale gas prospectivity of the Fraynes Formation in the exploration drill hole Manbulloo S1 through the reconstruction of the original source-rock characteristics and well log interpretation. Internal units inside the Fraynes Formation were defined according to sedimentary facies. The hydrocarbon generation potential was estimated from the calculated original total organic carbon content, hydrogen index and thermal maturity data measured from bitumen reflectance data. The shale total porosity was re-interpreted from bulk density logs by removing the organic matter effect, adding organic porosity for the organic-rich shales, and updating the water saturation. The maximum amount of gas generated from the organic-rich source rocks is 3969, 2769 and 1912 Mcf/a-ft assuming the kerogen compositions of 100% Type I, mix of 50–50% Type I and II, and 100% Type II, respectively. The richness of organic matter and interpreted water saturation (<100%) imply favourable shale gas prospectivity in the Fraynes Formation. This work expands our knowledge on the potential unconventional energy resources in the west of the greater McArthur Basin.

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.

Organic matter enrichment in shale deposited proximal to paleo-uplifts and its impact on shale gas exploration

Much of the global exploration and development of shale gas is focused on organic-rich shale deposited in basin or slope/basin margin settings. There is a clear need to assess the degree to which organic-rich shale deposited in other settings, notably proximal to paleo-uplifts, are promising shale gas prospects. Organic-rich sediments that accumulated proximal to paleo-uplifts are recognized globally and include the Cambrian Niutitang Formation, Ordovician-Silurian transition “hot shales”, and modern sediments of the Black Sea. Though the subject of recent research efforts, much remains to be learned of the mechanisms of organic matter enrichment of fine-grained sediment deposited adjacent to paleo-uplifts. Our study focuses on the Ordovician Wufeng Formation that accumulated proximal to uplifted areas of the Upper Yangtze platform. Though the TOC content of the analyzed Wufeng Formation samples recovered from near the paleo-uplifts is less than that of Wufeng samples collected from basin or slope/basin margin settings, average TOC value of the former can still reach more than 2%. Wufeng Formation shale deposited proximal to paleo-uplifts accumulated under conditions of medium to high paleoproductivity, elevated terrigenous clastic input and sedimentation rate, and oxic-suboxic water column conditions. Principal component analysis suggests that the factor most critical to organic matter enrichment of Wufeng deposits proximal paleo-uplifts was paleo-redox conditions. The TOC abundance in Wufeng Formation shale deposited during late Katian stage is higher than that of shale deposited during Hirnantian stage. It was at the Hirnantian stage that the paleo-uplifts became most active in association with the Kwangsian Orogeny resulting in diminished paleoproductivity and preservation conditions as reflected in the reduced organic matter abundance of associated shale. Uplift of the paleo-uplift of the Yangtze Platform, a manifestation of the Kwangsian Orogeny during the Ordovician-Silurian transition, appears to have been largely responsible for spatial and temporal distribution differentiation of organic matter abundance of the Wufeng Formation of the Upper Yangtze Platform. Results of the present study contribute supplementary information regarding the mechanism of organic matter enrichment in shale and can provide guidance for shale gas exploration and development in geologically similar regions.

Influence of Mineralogy, Organic Matter and Thermal Maturity on the Diagenetic Evolution of Pore Systems in the Shales of Cambay and Raniganj Basin, India

Abstract The mineral composition, organic matter, thermal maturity, and diagenesis control the shale reservoir properties, including the pore distribution, variable fluid distribution, microstructure, heterogeneity, etc. The shale layers of the Cambay Formation and the Raniganj Formation are considered prospective shale gas resources in India. This paper focuses on the detailed analysis of shale from the Cambay Formation (Eocene age) of the Cambay Basin and the Raniganj Formation (Permian age) of the Raniganj Basin, India. The whole rock X-ray diffraction data indicates that quartz is the dominant mineral in both the shales (Raniganj and Cambay shale) of the Raniganj and the Cambay Basin. The main clay minerals are clinochlore, smectite-kaolinite, illite, and kaolinite in the Raniganj shale, while kaolinite, montmorillonite, and illitesmectite are the dominant clay minerals in the Cambay shale. The total organic content (TOC) ranges from 4.97 to 17.88 wt.% and 1.16-7.6% in the Raniganj and Cambay shales respectively. For the studied shale section, the TOC shows a gradual decrease with respect to depth in both shale types. The Raniganj shale has 3.8 to 8.3 percent total porosity, and the Cambay shale contains 1.16 to 6.5% total porosity. The increasing thermal maturity with the higher TOC corresponds to the more developed organic pores in the Raniganj shale. In contrast, the secondary pores are developing in the Cambay shale due to dissolution activities and enhancing the storage capacity. The study infers that the mineral composition and diagenesis are playing a crucial role in the pore system evolution of the shale in both the basins.

Brittle tectonic evolution of Gondwana: implications for shale-gas and groundwater exploration

Abstract Brittle structures are crucial for enabling several key natural processes in the Earth's upper crust. In addition, understanding the 3D characteristics and geological evolution of these features is equally important to support various developmental objectives, such as those, inter alia , linked to natural gas, groundwater, hydrothermal minerals and seismicity. In this study, we map various fractures of Gondwana based on the available geological information, satellite imagery and digital elevation data. The lengths and orientations of more than 10 000 fractures in their present-day position reveal four clearly defined patterns, with those striking NW being predominant. Archean–Paleoproterozoic domains are defined by fractures oriented north and NE, whereas the Mesoproterozoic has dominant NNW-striking fractures. In contrast, the Neoproterozoic has mostly NE-striking fractures and the Phanerozoic sequences are defined by a predominant NW and a subordinate west fracture pattern. The style and geometry of these structures can be linked to major geodynamic events that led to the formation of Gondwana building blocks during the Eburnean ( c. 2.2–1.8 Ga), Kibaran ( c. 1.4–1.0 Ga) and Pan African–Brasiliano ( c. 800–550 Ma) orogens, and amalgamation of Pangaea ( c. 350–250 Ma). Many structures were reactivated and new faults formed during opening of the Atlantic and Indian oceans ( c. 180–120 Ma), the India–Asia collision and rifting across East Africa since about 40 Ma. Although the changes in palaeogeography remain difficult to model with accuracy, major structural orientations are corroborated by the occurrence of major mineral deposits and seismicity. The spatial distribution of mapped patterns across the different continents also correlates well with large shale gas prospects and increased groundwater yields. Thus, Gondwana fractures need to be considered in more detail for informing future development related to water and energy use, especially across regions of Africa.

A review of Pakistani shales for shale gas exploration and comparison to North American shale plays

Recent advancements in technologies to produce natural gas from shales at economic rates has revealed new horizons for hydrocarbon exploration and development worldwide. The importance of shale oil and gas has aroused worldwide interest after the great success of production in North America. In this study, different marine source rocks of Pakistan are evaluated for their shale gas potential using analogs selected from various North American shales for which data have been published. Pakistani formations reviewed are the Datta (shaly sandstone), Hangu (sandy shale), Patala (sandy shale), Ranikot (shaly sandstone), Sembar (sandy shale) and Lower Goru (shaly sandstone) formations, all of which are known source rocks in the Indus Basin. Available geological data of twenty-six wells (e.g., geological age, depositional environment, lithology and thickness), geochemical data (e.g., total organic carbon (TOC), vitrinite reflectance (Ro), rock pyrolysis analysis and maturity), petrophysical data (e.g., porosity and permeability) and dynamic elastic parameters estimated from logs (Young’s modulus and Poisson’s ratio) have been investigated. According to this study, the Pakistani shales are explicitly correlated with the most active shale gas plays of North America. The burial depths or geological position of the Pakistani shales are generally comparable to or slightly higher than the North American shales based on the available data. The thicknesses of the Pakistani (except for the Sembar shale) and North American shales fall in similar ranges. In terms of mineralogical composition, all of the Pakistani shales except the Ranikot and Hangu shales have quartz contents in the 40% to 50% range (approximately), which is similar to most of the North American shales. The high maximum TOC of the Hangu and Sembar shales (10%) is comparable to the New Albany, Antrim and Duvernay shales. The maximum TOC values for the Ranikot (3%), Lower Goru (1.5%) and Datta (2%) shales are lower than all North American shales. The TOC of Patal Shale (∼5%–10%) is comparable to Fayetteville and Eagle Ford shales. The geological and geochemical parameters of all the Pakistani shales reviewed in this work are promising regarding their shale gas prospects. However, geomechanical data are required before conclusions on these shales’ economic production can be made with confidence.

Effects of Regional Differences in Shale Floor Interval on the Petrophysical Properties and Shale Gas Prospects of the Overmature Niutitang Shale, Middle-Upper Yangtz Block

The lower Cambrian Niutitang/Qiongzhusi shale gas in the Middle-Upper Yangtz Block had been regarded as a very promising unconventional natural gas resource due to its high total organic carbon, great thickness, and large areal distribution. However, no commercial shale gas fields have yet been reported. From the northwest to the southeast there are considerable differences in the sedimentary environments, lithology, and erosive nature of the underlying interval (the floor interval) of the Niutitang shale. However, systematic research on whether and how these regional differences influence shale petrophysical properties and shale gas preservation in the Niutitang shale is lacking. A comparison of Niutitang shale reservoirs as influenced by different sedimentary and tectonic backgrounds is necessary. Samples were selected from both the overmature Niutitang shales and the floor interval. These samples cover the late Ediacaran and early Cambrian, with sedimentary environments varying from carbonate platform and carbonate platform marginal zone facies to continental shelf/slope. Previously published data on the lower Cambrian samples from Kaiyang (carbonate platform), Youyang (carbonate platform marginal zone) and Cen’gong (continental shelf/slope) sections were integrated and compared. The results indicate that the petrophysical properties of the floor interval can affect not only the preservation conditions (sealing capacity) of the shale gas, but also the petrophysical properties (pore volume, porosity, specific surface area and permeability) and methane content of the Niutitang shale. From the carbonate platform face to the continental shelf/slope the sealing capacity of the floor interval gradually improves because the latter gradually passes from high permeability dolostone (the Dengying Formation) to low permeability dense chert (the Liuchapo Formation). In addition, in contrast with several unconformities that occur in the carbonate platform face in the northern Guizhou depression, no unconformity contact occurs between the Niutitang shale and the floor interval on the continental shelf/slope developed in eastern Chongqing Province and northwestern Hunan Province. Such regional differences in floor interval could lead to significant differences in hydrocarbon expulsion behaviour and the development of organic pores within the Niutitang shale. Therefore, shale gas prospects in the Niutitang shales deposited on the continental shelf/slope should be significantly better than those of shales deposited on the carbonate platform face.

Use of Cluster Analysis to Group Organic Shale Gas Rocks by Hydrocarbon Generation Zones

In the last decade, exploration for unconventional hydrocarbon (shale gas) reservoirs has been carried out in Poland. The drilling of wells in prospective shale gas areas supplies numerous physicochemical measurements from rock and reservoir fluid samples. The objective of this paper is to present the method that has been developed for finding similarities between individual geological structures in terms of their hydrocarbon generation properties and hydrocarbon resources. The measurements and geochemical investigations of six wells located in the Ordovician, Silurian, and Cambrian formations of the Polish part of the East European Platform are used. Cluster analysis is used to compare and classify objects described by multiple attributes. The focus is on the issue of generating clusters that group samples within the gas, condensate, and oil windows. The vitrinite reflectance value (Ro) is adopted as the criterion for classifying individual samples into the respective windows. An additional issue was determining other characteristic geochemical properties of the samples classified into the selected clusters. Two variants of cluster analysis are applied—the furthest neighbor method and Ward’s method—which resulted in 10 and 11 clusters, respectively. Particular attention was paid to the mean Ro values (within each cluster), allowing the classification of samples from a given cluster into one of the windows (gas, condensate, or oil). Using these methods, the samples were effectively classified into individual windows, and their percentage share within the Silurian, Ordovician, and Cambrian units is determined.

Economic assessment of prospective shale gas play in Pakistan using discounted cashflow model

Economic assessment of prospective shale gas play in Pakistan using discounted cashflow model

Optimization of 2-D Magnetotelluric (MT) Modes Based on Data Dimensionality to Delineate Potential Area for Shale Gas Prospect in Kutai Basin, East Kalimantan, Indonesia

We conducted a study using the magnetotelluric method in the Kutai Basin, which is one of the largest and deepest tertiary sedimentary basin located in the province of East Kalimantan, Indonesia. The Kutai Basin, which is one of the sedimentary basin that is proven to produce hydrocarbons in Indonesia, also has the potential for shale gas with all the complexities of its geological structure. Inversion of 2-D MT can generally be done in three modes with different sensitivity. We perform data processing objectively to obtain the best quality data. We continued our data processing to the inversion process with a range from 80.78% to 97.09% coherency data. We also performed sensitivity skewness calculations to determine the dimensionality of our data. The map of sensitivity skewness is shown for the vertical path A – A’ with direction N – S in our study area. Based on the calculation results, the skewness value below 0.3 is obtained around the frequency 320 - 0.002 Hz, and associated with the 2-D structure while value above 0.3 are obtained around the frequency 0.00198 - 0.00034 Hz at KT34 and KT36 stations. Based on dimensionality calculations, it is concluded that the MT data in the Kutai Basin is dominated by 2-D structural responses, so that the TE + TM (invariant) mode is the best measurement mode for inversion modeling. We also performed calculations to obtain the optimum smoothness factor (tau) using a trade-off curve. Based on the results of the inversion with the optimization of these data parameters, we obtained a subsurface geological structure pattern such as fault and fold structure along the vertical path of A – A’. The low resistivity anomaly is interpreted as a response to the presence of black shale which is part of the Pamaluan Formation. The top of the Pamaluan Formation is estimated at the depth that varies from 2000m to 4000m below the surface along the A – A’ vertical cross-section.

Determining reservoir intervals in the Bowland Shale using petrophysics and rock physics models

SUMMARY An evaluation of prospective shale gas reservoir intervals in the Bowland Shale is presented using a wireline log data set from the UK's first shale gas exploration well. Accurate identification of such intervals is crucial in determining ideal landing zones for drilling horizontal production wells, but the task is challenging due to the heterogeneous nature of mudrocks. This heterogeneity leads to stratigraphic variations in reservoir quality and mechanical properties, and leads to complex geophysical behaviour, including seismic anisotropy. We generate petrophysical logs such as mineralogy, porosity, and organic content and calibrate these to the results of core studies. If ‘reservoir quality’ is defined by combined cut-offs relating to these parameters, we find that over 100 m of reservoir quality shale is present in the well, located primarily within the upper section. To examine the link between geophysical signature and rock properties, an isotropic rock physics model is developed, using effective medium theories, to recreate the elastic properties of the shale and produce forward-looking templates for subsequent seismic inversion studies. We find that the mineralogical heterogeneity in the shale has a profound impact on modelled elastic properties, obscuring more discrete changes due to porosity, organic content and water saturation and that the best reservoir quality intervals of the shale bear a distinctive response on rock physics cross-plots. Finally, we consider the density of natural fractures in the shale by developing an anisotropic rock physics model to reflect high-angle fractures observed on micro-imagery logs. We invert crack density using shear wave splitting well log data and find a crack density of up to 4 per cent which correlates well with micro-imagery observations. Our work further supports previous authors’ core-based studies in concluding that the Bowland Shale holds good reservoir characteristics, and we propose that there are multiple intervals within the shale that could be targeted with stacked horizontal wells, should those intervals’ mechanical properties also be suitable and there be adequate stress barriers between to restrict vertical hydraulic fracture growth. Finally, our rock physics templates may provide useful tools in interpreting pre-stack seismic data sets in prospective areas of the Bowland Shale and picking the best locations for drilling wells.

Bowland Shale well placement strategy – Part 1: Determining landing intervals using geomechanical properties

The production performance of a shale reservoir is directly affected by the geomechanical characteristics of the formation. A target shale interval will ideally develop hydraulic fractures upon stimulation that stay open with the aid of injected proppant. However, shales are geomechanically complex due to heterogeneities in their rock properties such as mineralogy and porosity and the extent to which they may be naturally fractured. These characteristics can complicate the task of identifying the ideal target interval for placing horizontal wells. Whilst the Bowland Shale is the UK's most prospective shale gas target, long horizontal wells are generally not feasible or practical in the Craven Basin, due to the existence of many, large-offset reverse faults and high bedding dips. An alternative to this approach could include drilling shorter, stacked horizontal wells targeting different stratigraphic intervals. However, it is unclear if there are enough intervals within the stratigraphic section with the desired geomechanical properties to target with stacked horizontal wells, nor if there are adequate intervals that can limit vertical hydraulic fracture growth between those wells. The absence of the latter may ultimately lead to well interference and reduced production. These issues were addressed by the creation of a series of wireline log-based geomechanical logs at well Preese Hall-1, calibrated to pressure test data. Aided by the results of a cluster analysis model, the upper section of the Bowland Shale was classified into geomechanical zones to identify the optimal intervals for hydraulic fracturing and barriers to vertical hydraulic fracture growth. Three intervals are highlighted with low effective stress, low fracture toughness and high brittleness which may form excellent landing zones. Importantly, these landing zones are also separated by intervals of high effective stress that may limit vertical hydraulic fracture growth and mitigate the risk of well interference.

Integrated Technical and Economical Methodology for Assessment of Undeveloped Shale Gas Prospects: Applying in the Lurestan Shale Gas, Iran

Shale gas resources can supply the substantial growing demand for clean energy. In comparison with conventional reservoirs, shale gas reservoirs have lower production potential, and selecting the most favorable areas from the broad region of shale gas prospect is very crucial in commercial development. These areas are screened regarding some key evaluation indicators that affect the ultimate recovery of shale gas reservoirs. Many attempts have been made to screen sweet spots by applying the different evaluation indicators. These studies mainly focus on geological sweet spot identification without considering the economic indicators that may influence the order of geological sweet spots for development. The current study introduces a methodology for selecting the best techno-economic spots in undeveloped shale gas regions by integrating the technical and economic criteria. The techno-economic areas are defined as the geological sweet spots with the highest rate of return under the currently employed technology. The economic objective functions for selecting these areas are net present value, internal rate of return, and payback time. To estimate the unknown features for integrating the technical and economic criteria in undeveloped areas, an analogy study is applied. Due to the large number of unknowns and uncertainties in shale gas evaluation and low confidence of deterministic results, a probabilistic approach is used. As the first attempt in shale gas assessment in Iran, the Lurestan shale gas region is evaluated by applying this approach. The results indicate that no selected geological sweet spots in this region are commercial regarding the current cost rates and the available technology in Iran, and it can be considered as a future affordable source of energy.

Application of Elemental Geochemistry in High-Frequency Sequence—Stratigraphic Analysis of Lacustrine Shale

The successful development of shale gas and oil in North America has created considerable interest in shale. The analysis of genetic types, the sedimentary environment, and the mudstone development mechanism within sequences is critical for evaluating shale gas and oil exploration prospects, exploration favorable zones, and resource potential. This study focused on the shale of Shahejie Formation in Dongying Depression of Bohai Bay Basin. Shale lithofacies division, geochemical analysis, and well-log analysis were performed for a sedimentary environment and its related elemental response characteristics’ identification. Based on the results, we concluded that the sedimentary environment of the lake basin evolved from the saltwater lake to the ambiguous lake and then the open lake to the delta. In response, we observed gradually decreasing Sr/Ba and Ca/Mg ratios and increasing Rb/Ca and Fe/Mn ratios during the whole process during the reduction of the salinity and the decrease in PH value and sediments’ transport distance. The relationship between ratio elements and high-frequency sequences was initially established within the shale strata. Our results show that ratios of Sr/Ba and Ca/Mg ratios near the sequence boundary are relatively low, and ratios of Fe/Mn and Rb/Ca are relatively high, while ratios of Sr/Ba and Ca/Mg near the flooding surface are relatively high, and ratios of Fe/Mn and Rb/Ca are relatively low. Those features can be used as a marker for high-frequency sequence division of shale strata. Our results provided a new theoretical basis and technical method for shale gas and oil exploration and development.

Pore structure and sorption capacity investigations of Ediacaran and Lower Silurian gas shales from the Upper Yangtze platform, China

The shale gas potential of Ediacaran and Lower Silurian shales from the Upper Yangtze platform is assessed in this study with a focus on the contributions of clay minerals and organic matter to sorption capacity. For this purpose, a multidisciplinary assessment was carried out using petrophysical, mineralogical, petrographic and geochemical methods. In terms of TOC contents (4.2%), brittle mineral contents (68.6%) and maximum gas storage capacities (0.054–0.251 mmol/g) Ediacaran shales from this study show comparable properties to other producing shale gas systems although the thermal maturity is extremely high (VRr = 3.6%). When compared to lower Silurian shales from the same region, it is evident that (1) deeper maximum burial and (2) a lack of silica-associated preservation of the pores resulted in a relatively lower mesopore volume, higher micropore volume fraction and lower overall porosity (Ediacaran shales: 1.4–4.6%; Silurian shales: 6.2–7.4%). Gas production is therefore retarded by poor interconnectivity of the pore system, which was qualitatively demonstrated by comparing experimental gas uptake kinetics. TOC content exhibits a prominent control on sorption capacity and micropore volume for both shales. However, different contributions of clay minerals to sorption capacity were identified. This can partly be attributed to different clay types but is likely also related to burial-induced recrystallisation and different origins of illite. Additionally, it was shown that variations in sorption capacity due to incorrect estimates of clay mineral contribution are in the same range as variations due to differences in thermal maturity.Article highlightsPore structure and gas storage characteristics are evaluated for the first time for Ediacaran Shales from the Upper Yangtze platformDue to a lower free gas storage capacity and diffusivity, the Ediacaran shale can be regarded as a less favorable shale gas prospect when compared to the Silurian shaleClay mineral contribution to sorption capacity is evaluated taking clay mineralogy into considerationMaturity-related changes of organic matter sorption capacity have been discussed on the basis of a compiled data set

An integrated approach to evaluate the unconventional hydrocarbon generation potential of the Lower Goru Formation (Cretaceous) in Southern Lower Indus basin, Pakistan

Southern Lower Indus basin is an oil and gas prone basin, which is important for producing hydrocarbon in Pakistan. Due to limited Rock-Eval pyrolysis data availability in the prospective shale gas basin, the organic facies geochemical characteristics study is a challenging task for researchers. The primary objective of this study is an evaluation of the Lower Goru Formation organic facies hydrocarbon potential by geochemical data and its subsurface facies distribution study by well tops and seismic data. The study area is situated at the Southern Lower Indus basin of Pakistan that is considering the prospective shale gas basin with immense unconventional hydrocarbon potential. In the present study, Rock-Eval pyrolysis data analysis along with the integration of both seismic and well tops data were conducted for investigation of source rock generation potential of organic facies variability within the Lower Goru Formation. The geochemical approaches used in the current study show that the Lower Goru Formation encountered in, bears fair to excellent total organic carbon (TOC) content values of 0.50–3.60% in Well-A and 0.10–4.69% in Well-B. Additionally, the results of Rock-Eval pyrolysis data show that interbedded shales of the Lower Goru Formation contain different types of kerogen (III, II–III, and II) with variable generation potential of oil and gas.

The Permian Tunas Formation (Claromecó Basin, Argentina): Potential naturally fractured reservoir and/or coal bed methane (CBM) play?

The analysis of structural discontinuities in the Tunas Formation helps characterize this unit as a potential naturally fractured reservoir. The principal discontinuities are 1) fractures parallel to the bedding planes, 2) fractures coplanar to the axial planar cleavage, 3) dilatant fractures filled by quartz, and 4) subvertical shear fractures. Over a thousand measurements on microtectonic structures help infer a stress field whose maximum principal stress (σ1) has a SW-NE orientation. Based on this structural analysis, optimal orientations for exploration and/or production wells in the Claromecó Basin should be a 130° azimuth. Fracture spacing range between 30 and 100 cm in outcrops of the Tunas sandstones along the Ventana foldbelt (VFB). A similar fractured network is postulated for the subsurface of the basin.Organic-rich levels, ranging from coals to carbonaceous shales, occur in the Tunas Formation in the subsurface of the Claromecó Basin and are a potential shale gas resource play. These beds tend to cap successions of interbedded shales and sandstones. The coals range from semi anthracitic to low volatile bituminous. Vitrinite and fusinite prevail as organic matter types, ranging between 1.3 and 2.4 vitrinite reflectance (Ro). The occurrence within condensate-wet gas to dry gas windows reflect subsurface processes such as strong diagenesis and anchimetamorphism. The coal-rich levels in the Tunas Formation can be correlated with other Lower Permian organic-rich units in the Paraná Basin in Uruguay (Tres Islas Formation) and Brazil (Rio Bonito Formation). All are analogous to the lower Upper Permian Vryheid coals of the eastern Karoo Basin in South Africa with shale gas and coal bed methane (CBM) prospectivity.

Geological and Bioregional Assessments: assessing the prospectivity for tight, shale and deep-coal resources in the Cooper Basin, Beetaloo Subbasin and Isa Superbasin

The Geological and Bioregional Assessment Program is a series of independent scientific studies undertaken by Geoscience Australia and the CSIRO, supported by the Bureau of Meteorology, and managed by the Department of Agriculture, Water and the Environment. The program consists of three stages across three regions with potential to deliver gas to the East Coast Gas Market. Stage 1 was a rapid regional prioritisation conducted by Geoscience Australia, to identify those sedimentary basins with the greatest potential to deliver shale and/or tight gas to the East Coast Gas Market within the next 5–10 years. This prioritisation process assessed 27 onshore eastern and northern Australian basins with shale and/or tight gas potential. Further screening reduced this to a shortlist of nine basins where exploration was underway. The shortlisted basins were ranked on a number of criteria. The Cooper Basin, the Beetaloo Subbasin and the Isa Superbasin were selected for more detailed assessment. Stage 2 of the program involved establishing a baseline understanding of the identified regions. Geoscience Australia produced regional geological evaluations and conceptualisations that informed the assessment of shale and/or tight gas prospectivity, ground- and surface-water impacts and hydraulic fracturing models. Geoscience Australia’s relative prospectivity assessments provide an indication of where viable petroleum plays are most likely to be present. These data indicate areal and stratigraphic constraints that support the program’s further work in Stage 3, on understanding likely development scenarios, impact assessments and causal pathways.

Hydrocarbon Generation Potential of the Campano-Maastrichtian Dark Mudstone Lithofacies, Benin Flank, South West Anambra Basin, Nigeria

The dark mudstone lithofacies of Mamu Formation was deposited during the Campano-Maastrichtian flooding episode. It is laterally heterogeneous, and has been subdivided into marsh, bay and central basin subenvironments in order of proximality. Arising from recommendation from a previous study, we evaluated its hydrocarbon generating potential using multidisciplinary tools involving visual kerogen analysis, as well as bulk and isotope geochemistry. Seventy-seven sample materials were taken from 3-outcrop sites at Uzebba, Okpekpe and Imiegba locations, Benin flank, SW Anambra Basin, Nigeria. The results show that bulk of the samples have good organic richness. Kerogen quality is dominantly of gas prone Type III kerogen. However, visual kerogen analysis indicates the presence of an oil prone Type II/III kerogen in the central basin subenvironments. An immature thermal maturity is inferred based on spore colour index (SCI) of less than 6 on the SCI chart (thermal alteration index of <2.5). In addition, we hypothesize that the dark mudstone lithofacies possesses biogenic gas potential based on its organic richness, kerogen quality and thermal maturity. Shale gas prospectivity is further enhanced by the low dip of the Mamu Formation, shallow burial as well as high silica content. Worth mentioning is the proximal marsh mudstone (Uzebba location) with suitable microfabric, very high silica as well as >10m of combined (continuous) outcropping and subcropping thickness
 Keywords: Kerogen, palynofacies, stable isotope geochemistry, shale gas,