As government policy, consumer markets, and global geopolitics rapidly shift, it will be imperative that energy companies, universities, and government organizations have access to research that addresses the subsurface development of energy. A key area of research for the energy transition is related to the precipitation, deposition, and diapirism in salt basins. Traditionally, evaporite stratigraphy and diapirism have been of great interest to the oil and gas industry because of the active petroleum systems and will continue to be valuable, especially from an energy security perspective. Energy security is important for several reasons, as it has significant implications for a country’s economy, national security, and overall stability. Here are some key reasons that highlight why energy security matters.

ABSTRACT Post-Permian salt tectonic processes and their relationship with varied paleodepositional systems were a major controlling factor of the Mesozoic–Cenozoic basin evolution of the Southern North Sea. Detailed mapping and analysis of Zechstein salt structure morphologies is vital to conduct regional kinematic analysis and evolution of salt structures as well as understanding the relationship between thick- and thin-skinned tectonics across the basin. This study uses the supraregional Petroleum Geo-Services Southern North Sea three-dimensional seismic MegaSurvey for the systematic identification and classification of salt structure morphologies using seismic attributes and validation with regional seismic sections. The smoothed dip of maximum similarity attribute is used to highlight abrupt changes in the values of the attribute, which correspond to sudden changes in dip angle indicating faults or the edges of diapiric structures, whereas gradual changes in the attribute value coupled with the longer wavelength of structures correspond to salt anticlines. Of the 224 salt structures developed across the Southern North Sea, 119 were classified as concordant and 79 as discordant, with 26 having concordant and discordant flanks. Validation of these maps with regional seismic sections allows salt structures to be classified into salt anticlines, salt anticlines with a crestal graben, reactive diapirs, salt diapirs (walls and stocks), and salt overthrusts. This study provides guidelines for identifying different salt structure morphologies based on their seismic attribute signature, which could be applied to other salt basins around the world.

The Mesoproterozoic Velkerri and Kyalla Formations in the Beetaloo Sub-basin in northern Australia contain the world's oldest shale plays.In unconventional exploration, the main challenge is the identification of sweet spots from which hydrocarbons can be produced economically.In fine-grained siliciclastic intervals, the distribution of these sweet spots is controlled mainly by the evolution of the sedimentary system and its effects on organic matter distribution.This work reconstructs the stratigraphic architecture of the Velkerri-Kyalla interval and integrates its interpreted stratigraphic evolution with chemostratigraphic and chronostratigraphic data sets.Based on core descriptions and well correlations, we reconstructed the facies distribution within the Velkerri-Kyalla interval along two regional well sections.This allowed stratigraphic stacking patterns to be observed and multiple depositional sequences to be identified.Three stratigraphic orders are observed within the Velkerri-Kyalla Formations.The studied interval is interpreted to comprise one second-order depositional sequence that contains four nested third-order depositional sequences.These, in turn, are composed of 13 nested fourth-order transgressive-regressive sequences.By integrating the sequence stratigraphic architecture with available geochronological constraints, we postulate a chronostratigraphic framework for these Mesoproterozoic strata.The Velkerri Formation was likely deposited between 1420 and 1300 Ma and the overlying Kyalla Formation between 1270 and 1210 Ma.Furthermore, by coupling the sequence stratigraphy, chemostratigraphy, existing provenance studies, and chronostratigraphy, we were able to construct regional

Abstract The hydrocarbon isotope geochemistry of coalbed methane is determined by fractionation during its generation, migration, and accumulation. The isotope can be used to identify the origin type and also provide a basis for the selection of favorable blocks for coalbed methane exploration and development. In this paper, the anaerobic fermentation of coal was conducted to generate primary biogenic gases. The carbon and hydrogen isotopes, liquid organic compounds, and microbial communities were analyzed using isotopic mass spectrometry, gas chromatography–mass spectrometry, and high-throughput sequencing methods. The results show that acetolactic methane was generated first and had the lowest carbon isotope; methylotrophic methane was produced in the early-middle stage and had moderate carbon isotope; and hydrotropic methane was generated at the middle-late stage and featured a broader carbon isotope distribution. The production of methane differs significantly between carbon and hydrogen isotopes produced in the laboratory and those of natural methane. This is caused by a series of fractionations induced by dissolution, adsorption, desorption, and diffusion of microbial methane during migration and accumulation.

Abstract The rule-based modeling method applies stratigraphic rules that simulate the fundamental geological processes to generate numerical subsurface models. Even though rule-based models rely upon a few simple and intuitive rules, they can create complicated and realistic reservoir heterogeneity, continuity, and spatial organization. The application of this modeling approach has now been applied to a variety of depositional settings, such as the deepwater turbidites, efficiently capturing the salient geological spatial features of compensational stacked lobes. Questions remain as to how the integration of geological rules and related parameters affect the forecasting of fluid flow, including oil production. A large experiment was conducted using a rule-based model for a deepwater lobe system controlled by three key geological parameters: (1) the vertical and lateral stacking of geobodies, described as a compensation index; (2) lobe geometry/size; and (3) permeability heterogeneity. Regression analysis and computational physics–based fluid flow simulation are applied to examine reservoir production sensitivity to these three geological input parameters. Over the early production stage, the permeability heterogeneity within depositional elements is the most influential reservoir parameter. However, over time, lobe geometry and compensation index have a more significant impact on production. This result suggests that the importance of geological features to the flow behavior changes over time as longer-term production is influenced by a larger rock volume and compounding heterogeneity. Moreover, understanding the impact of compensational stacking and deepwater lobe geometry is essential for performance forecasting, uncertainty analysis, and history matching. The importance of these key geologic parameters further supports the necessity of outcrop characterization, high-resolution seismic interpretation and flume experiments, and the use of reservoir models, such as stratigraphic rule-based models that reproduce these critical stratigraphic features.

This study uses minimal prior information to place into context the exploration potential for two prospects that lack well information in the Pelotas and Punta del Este Basins, offshore Uruguay.Prospect A is representative of a typical prospect within the Cretaceous turbidite play, interpreted to be charged by marine Aptian shales, with an Albian sandstone reservoir sealed by Cenomanian shales during a regional transgression, trapped in a structural-stratigraphic trap.Prospect B is representative of a typical prospect within the Cretaceous shallow-marine sandstone play, charged by Barremian lacustrine shales into Maastrichtian reservoirs, sealed by transgressive Paleocene shales, in stratigraphic pinch-outs and/or subunconformity truncation traps.Prospects A and B were benchmarked using four filters that restricted analogues to similar hydrocarbon type, reservoir age, depositional environments, and trapping mechanisms.The resulting analogue population can be used to reduce uncertainty and quantify the potential of the prospects.Prospect A's interpretation is on the high side of the analogue distribution since both the productive area and original oil in place do not exceed the 10th percentile of observed data of the analogue data set.Significant uncertainty exists for prospect B as currently defined, but analysis of the context of the play and prospect suggests that the appropriate conditions exist to be a viable play.This workflow can be used in a variety of low-data situations to increase confidence in interpretation and decrease risk