Conventional Hydrocarbon Resources Research Articles

Experimental investigation of hydrocarbon generation, retention, and expulsion of saline lacustrine shale: Insights from improved semi-open pyrolysis experiments of Lucaogou Shale, eastern Junggar Basin, China

The organic-rich shale deposited in a saline lacustrine setting contributes massive conventional and unconventional petroleum reserves. However, the hydrocarbon generation, retention, and expulsion of saline lacustrine shale with increasing thermal maturity were rarely reported. Predicting the quality and quantity of generated, retained, and expelled hydrocarbons under various maturity stages for a given shale before drilling persists as a vital issue in exploration. Here, this study conducted two improved semi-open pyrolysis experiments to investigate the characteristics of the hydrocarbon generation, retention, and expulsion of Lucaogou Shale. Solid residues, adsorbed oil, free oil, expelled oil, and hydrocarbon gases were carefully quantified during the pyrolysis experiments. The results reveal that the composition and quantity of generated hydrocarbons are determined by the maturity and degree of openness of the shale system. The Tasmanites of Lucaogou Shale rapidly were converted to abundant oil in the main oil stage, promoting oil retention and expulsion. Meanwhile, the yield of adsorbed and free oil reached its peak at the VRo of 1.01 %. In the late oil window, the previously retained oil was further expelled from the shale as thermal stress increased. High oil retention significantly promoted the generation of extensive wet gas due to secondary cracking within the gas window. However, in a more open system, most of the generated oil was expelled within the oil window. The Lucaogou Shale generates relatively small amounts of hydrocarbon gas through kerogen cracking within the gas window. Hence, the extent of oil transformation into gas is controlled by the residence time and quantity of retained oil in shale. In addition, the maturity range of the oil saturation index greater than 100 mg oil/g TOC in Lucaogou Shale is relatively wide (VRo of 0.9 %-1.5 %), consistent with the renowned Woodford Shale. Expanded geochemical data of natural shale and artificial maturation experiments indicate the distribution of potential hydrocarbon resources. These valuable insights enhance the possibility of searching for commercial shale oil and conventional hydrocarbon resources. Collectively, these findings provide critical new insights into the hydrocarbon generation, retention, and expulsion of saline lacustrine shale, and the results could be a valuable analog for other saline lacustrine petroleum systems worldwide.

Pore Space as a Resource: A Discussion of the Policy and Regulatory Framework for Carbon Capture, Utilization, and Storage

Reinforced by the International Energy Agency (IEA), carbon capture, utilization, and storage (CCUS) is currently the only available group of technologies that reduce emissions in key hard to abate sectors and capture CO2 emissions that enable low carbon value chains such as hydrogen. Further, CCUS and carbon management play a critical role in achieving future global climate and energy goals. In fact, the Intergovernmental Panel on Climate Change and the IEA state that there is no viable path to net zero emissions without CCUS and other carbon management technologies. Due to concerns regarding energy security and an increase in energy demand, generation of energy from conventional hydrocarbon resources continues to be vital. In Alberta, CCUS is a necessary tool to align provincial climate change goals with the responsible and competitive market of energy production. Canada’s oil and gas sector has been an early innovator and adopter of CCUS. Given the petroleum and natural gas resources available in the Western Canadian Sedimentary Basin, and the decades-long energy industry expertise established in connection therewith, there is significant potential to further utilize CCUS to create a CCUS-based value chain. This article provides an overview of the current Canadian regulatory frameworks enabling CCUS, with a focus on the regulatory framework and development in Alberta. Specific topics include: (1) an overview of the regulatory frameworks governing CCUS in key jurisdictions in Canada, including Alberta; (2) an overview of the frameworks for the generation of offset credits from environmental attributes associated with a given project or activity, including both federal and provincial carbon credits and clean fuel credits; (3) a discussion of gaps in policy and legislation; (4) options for regulating “open access” CCUS hubs and CO2 pipelines; and (5) an overview of the various governmental incentives for CCUS projects, including federal and provincial tax credits.

Mineralogical Characterization From Geophysical Well Logs Using a Machine Learning Approach: Case Study for the Horn River Basin, Canada

AbstractAccurate estimation of mineral composition is essential for refined reservoir characterization, thermal conductivity and mechanical determinations of sedimentary rocks, but is extremely challenging in shale units due to the mineralogical complexity, low porosity and ultra‐low permeability. Direct mineral measurements derived from laboratory X‐ray diffraction (XRD) analysis on core samples and borehole geochemical logging tool (GLT), and conventional geophysical logs from vertical wells penetrating sediments are widely available in some basins, which enables detailed mineralogical characterization of a well. A hybrid machine learning (ML) architecture that improves model training and validation by combining convolutional neural network (CNN) with XGBoost allows accurate description of the mineralogical compositions across a basin. We applied this ML approach to predict the mineral compositions using conventional well logs from the Horn River Basin, northeast British Columbia, Canada, where extensive drilling for shale‐gas and conventional hydrocarbon resources, complemented by high temperature geothermal energy potential is ideal for case testing. The predicted mineral compositions from the ML approach are consistent with the mineralogical readings from the GLT and are confirmed by the XRD mineral measurements. This allows basin‐wide mineral compositions mapping that reveals spatial trends of major mineral compositions and their relationship with the previously recognized geomechanical and geological features, which have important implications for thermal conductivity modeling, reservoir evaluation and extensive geological studies.

Quantitative effect of kerogen type on the hydrocarbon generation potential of Paleogene lacustrine source rocks, Liaohe Western Depression, China

Kerogen types exert a decisive effect on the onset and capacity of hydrocarbon generation of source rocks. Lacustrine source rocks in the Liaohe Western Depression are characterized by thick deposition, high total organic carbon (TOC) content, various kerogen types, and a wide range of thermal maturity. Consequently, their hydrocarbon generation potential and resource estimation can be misinterpreted. In this study, geochemical tests, numerical analysis, hydrocarbon generation kinetics, and basin modeling were integrated to investigate the differential effects of kerogen types on the hydrocarbon generation potential of lacustrine source rocks. Optimized hydrocarbon generation and expulsion (HGE) models of different kerogen types were established quantitatively upon abundant Rock-Eval/TOC/vitrinite reflectance (Ro) datasets. Three sets of good–excellent source rocks deposited in the fourth (Es4), third (Es3), and first (Es1) members of Paleogene Shahejie Formation, are predominantly types I–II1, II1–II2, and II–III, respectively. The activation energy of types I–II2 kerogen is concentrated (180–230 kcal/mol), whereas that of type III kerogen is widely distributed (150–280 kcal/mol). The original hydrocarbon generation potentials of types I, II1, II2, and III kerogens are 790, 510, 270, and 85 mg/g TOC, respectively. The Ro values of the hydrocarbon generation threshold for type I–III source rocks gradually increase from 0.42% to 0.74%, and Ro values of the hydrocarbon expulsion threshold increase from 0.49% to 0.87%. Types I and II1 source rocks are characterized by earlier hydrocarbon generation, more rapid hydrocarbon expulsion, and narrower hydrocarbon generation windows than types II2 and III source rocks. The kerogen types also affect the HGE history and resource potential. Three types (conventional, tight, and shale oil/gas) and three levels (realistic, expected, and prospective) of hydrocarbon resources of different members in the Liaohe Western Depression are evaluated. Findings suggest that the Es3 member has considerable conventional and unconventional hydrocarbon resources. This study can quantitatively characterize the hydrocarbon generation potential of source rocks with different kerogen types, and facilitate a quick and accurate assessment of hydrocarbon resources, providing strategies for future oil and gas exploration.

Effect of Matrix Permeability on a Horizontal Shale Gas Well Performance using a Fully Coupled Fluid Flow with Geomechanics Model

Recently, hydrocarbon production from unconventional oil and gas resources has emerged. The most common unconventional oil and gas resources are found in shale formations. These shale formations are well-known for being stress-sensitive. Usually, traditional tools are used to model and study production from such formations. However, conventional modeling techniques denote rock deformation using constant rock compressibility. Such an approach is useful for studying conventional hydrocarbon resources where formation stress sensitivity is insignificant. However, when it comes to modeling stress-sensitive formations such as shale formations, it is important to include the rock deformation and its effects on the overall fluid flow in porous media. To consider the rock deformation in the fluid flow model, the coupling of fluid flow with the geomechanics model has to be used. This study utilizes a fully coupled fluid flow with a geomechanics model. In addition, shale formations are also known to have an ultra-low matrix permeability, and production usually results from hydraulic fractures that act as flow conduits. Consequently, the effect of matrix permeability on hydrocarbon production is rarely studied. This study focuses on the effect of matrix permeability on the production performance of a single horizontal well in Barnett Shale. It also focuses on the effect of matrix permeability on production performance when the geomechanics effects are coupled with the fluid flow model and decoupled. The results show that the higher the matrix permeability, the better the production performance of the well. The results also show that the higher the matrix permeability, the higher the estimated cumulative production difference between the two models (when the geomechanics effects are coupled and decoupled).

Salt Diapir‐Driven Recycling of Gas Hydrate

AbstractBy harnessing both hypothetical, synthetic basin and gas hydrate (GH) system models and real‐world models of well‐studied salt diapir‐associated GH sites at Green Canyon (Gulf of Mexico) and Blake Ridge (U.S. Atlantic coast), we propose and demonstrate salt movement (and in particular, diapirism) to be a new mechanism for the recycling of marine GH. At Green Canyon, for example, we show that by considering this newly proposed diapir‐driven recycling mechanism in conjunction with previously proposed lithological control on sandy‐reservoir‐hosted hydrate at the base of the GH stability zone (BGHSZ; ∼bottom‐simulating reflector, BSR), modeled GH saturations match drilling data. Overall, salt diapir movement‐induced GH recycling provides a temperature‐driven mechanism by which GH saturations at the BGHSZ may reach >90 vol. % and by which GH volumes near and free gas volumes beneath the BGHSZ may be increased significantly through time. Interestingly, comparison of salt diapir‐driven recycling and sediment burial‐driven recycling scenarios suggests notably higher rates of recycling via diapir‐driven versus burial‐driven processes. Our results suggest that GH and associated free gas accumulations above salt diapir crests represent particularly attractive targets for unconventional and conventional hydrocarbon resource exploration and for scientific and academic drilling expeditions aimed at exploiting GH systems. Salt basins containing GH systems—including passive margin basins of the Gulf of Mexico, southeastern Brazil, and southwestern Africa—are therefore compelling localities for studying salt‐driven GH recycling and for salt diapir‐associated natural gas exploration.

A Data-Driven Approach to the Unified Evaluation of Conventional and Unconventional Hydrocarbon Resources: Application to Low-Mature to Mature Source Rocks in the Liaohe Western Depression

Hydrocarbon potential evaluation is a high priority in oil/gas exploration which is significantly influenced by evaluation methods and subjective cognition. With the aim of quantitatively establishing a hydrocarbon generation and expulsion (HGE) model of source rocks, a data-driven approach is proposed based on abundant and readily available Rock-Eval/total organic carbon content (TOC)/vitrinite reflectance (VRo) datasets. This approach takes into account the original hydrocarbon generation potential (GPIo) and the loss of TOC. Hydrocarbon generation simulation was also adopted in this study. This data-driven method was applied to the Lower Paleogene Shahejie Formation (Es4), which has three sets of superior source rocks (average thickness > 250 m, TOC > 3%). The GPIo of the Es4 low-maturity source rock was 600 mg HC/g TOC. The initial maturity values of hydrocarbon generation and expulsion were 0.36% and 0.46%, respectively. The Gaosheng sub-member of the Es4 source rock had the largest amount of hydrocarbon generation but a limited amount of hydrocarbon expulsion, implying a favorable exploration of shale oil resources. By contrast, the values of the conventional, unconventional tight, and shale oil resource potentials of the Niuxintuo sub-member were 3.20 × 107, 7.70 × 107, and 5.93 × 108 t, respectively, indicating good prospects for tight oil and shale oil exploration. A comparison between the previous method and the data-driven method showed considerable differences in the restoration of GPIo and TOC, and both had their own limitations. This data-driven approach provides a quick and valid source rock evaluation method and can greatly enhance the accuracy of resource assessment.

Experimental study on the enhanced ultra-heavy oil recovery using an oil-soluble viscosity reducer and CO2 assisted steam flooding

Ultra-heavy oil resources have gained extensive attention due to their abundant reserves and the shortage of conventional hydrocarbon resources. In this work, we investigate the feasibility of recovering ultra-heavy oil resources using an oil-soluble dissolver, i.e., a type of viscosity reducer, and CO2 assisted steam flooding (DCS flooding) by studying the impact of those agents on oil properties and EOR performance of this approach. Firstly, the effects of steam, CO2, and the oil-soluble dissolver on the oil properties are investigated by comparing the variations in oil viscosity, SARA (saturates, aromatics, resins, and asphaltenes) compositions, asphaltenes structural parameters, and asphaltenes morphology. Then, the feasibility of DCS flooding in improving ultra-heavy oil recovery is investigated by comparing its performance in core flooding experiments with steam flooding and CO2 assisted steam flooding schemes. Next, the sensitivity of various agents in DCS flooding is analyzed by conducting DCS flooding experiments with different amounts and concentrations of those agents. Finally, the chemical components of the produced fluids are analyzed to further understand the dynamic EOR mechanisms of the DCS flooding. The results demonstrate that the oil-soluble dissolver exhibits the best oil viscosity reduction (56.1%) performance through decomposing the asphaltenes of ultra-heavy oil. Meanwhile, DCS flooding presents promising performance in improving ultra-heavy oil recovery (76.78%) compared with steam flooding (59.6%) and CO2 assisted steam flooding (65.26%). Moreover, DCS flooding is also beneficial to decrease maximum steam injection pressure, control the water cut, and improve steam dryness.

An Improved Computational Learning-Based Model for Estimating Total Organic Carbon in Unconventional Shale Reservoirs

Unconventional resources have emerged as one of the crucial alternatives to the rapidly depleting of conventional hydrocarbon resources. The hydrocarbon potential of shale source rocks is assessed by the percentage of the organic index such as total organic carbon (TOC). Correct estimation of TOC is very important since minor deviations in anticipated results can lead to wastage of investments and time. A slight improvement in estimation practices, on the other hand, can increase the value of an exploration project. Therefore, the objective of this study is to present an improved classification and regression tree (CART) computational learning-based model as an improved alternative in estimating TOC from well logging data. Conventional well logs suite of bulk density, gamma-ray, deep resistivity, sonic transit time, spontaneous potential, and neutron porosity from Mihambia, Mbuo and, Nondwa, Formations of the Mandawa Basin Tanzania, were used as input variables. Results from the developed CART TOC model were compared with the random forest (RF) and backpropagation neural network (BPNN). It was observed that the proposed CART model trained better while generalizing better through unused testing data compared with RF and BPNN. CART model achieved R, RMSE, and MAPE values of 0.9615, 0.0840, and 0.5035 for training and 0.9703, 0.1162, and 0.3722 for testing respectively. The proposed model work with higher accuracy with the sensitivity analysis indicating that gamma-ray, deep resistivity, and sonic transit time significantly influenced the model outcome.

Subsurface Relationships between the Sebree Trough and Carbonate-Siliciclastic Mixing in the Upper Ordovician Lexington-Trenton and Point Pleasant-Utica Intervals in Ohio, USA, using Multivariate Statistical Well Log Analysis

The Upper Ordovician (lower Katian; upper Chatfieldian-lower Edenian) Lexington-Trenton limestone and Point Pleasant-Utica shale intervals are important subsurface stratigraphic units across Ohio as they are the sources of significant conventional and unconventional hydrocarbon resources. However, both units exhibit anomalous distributions across the state and heterogeneous relationships, especially in areas where they intertongue. The limestone units show a peculiar SW-NE thinning trend across Ohio, whereas the overlying shale units show an anomalous thickening along the same trend—a trend associated with the poorly understood Sebree Trough, a supposed Late Ordovician paleobathymetric low related to the coeval Taconic Orogeny. To explore relationships amon Lexington-Trenton carbonates, Point Pleasant-Utica shales, and the presumed Sebree Trough, multivariate statistical analysis was used to compare geophysical well logs across the state with well logs referenced to the mineral content of 4 Lexington-Trenton-Point Pleasant-Utica cores. Comparing well-log responses with the mineral content of the reference cores allowed the discernment of 10 electrofacies, keyed to lithofacies in the cores. Software analysis of many other well logs across the state then made electrofacies assignments by comparing well-log responses from the other wells with well-log responses from the reference cores preset into the software. Electrofacies responses were color-coded, mapped in wells at 0.6 m (2 ft) resolution, and used to make section lines and isopach maps of similar electrofacies. Isopach maps and cross sections confirm the presence of the Sebree Trough across Ohio, with trends that parallel existing and projected basement structures. This suggests that the Sebree Trough in Ohio was a bathymetric low, which was, at least in part, controlled by reactivation of basement structures due to far-field Taconic stresses.

Hydrocarbon potential of shales and lignites of Oligocene-Miocene Ogwashi-Asaba formation exposed in Issele-Uku of Anambra Basin, Southern Nigeria as both conventional and unconventional resources

Hydrocarbon potentials of lignites and shales of Oligocene-Miocene Ogwashi-Asaba Formation outcropping along springs at Issele-Uku and Azagba-Ogwashi areas of Anambra Basin, Southern Nigeria were investigated through total organic carbon (TOC), Rock-Eval pyrolysis and organic petrology analyses. Lignite has an average TOC of 47.20 wt.% and shale of 9.15 wt.%, suggesting good to excellent source rocks. Sporinite, resinite, and humodetrinite are the dominant sub-maceral. Ratios of average huminite, liptinite, and inertinite maceral group (H:L:I) in lignite from Nnem-Agadi, Iyiodo, Mgbala, and Nkpunkpa are 55:35:10, 66:24:10, 62:25:13, and 58:30:12, respectively, while for shales in Nnem-Agadi is 57:28:15 and Iyiodo is 55:20:15. Average hydrogen index (HI) of lignite is 436 mgHC/gTOC, and shale is 218 mgHC/gTOC. HI of 783 mgHC/gTOC in one lignite from Nnem-Agadi indicates Type I oil-prone kerogen typical of algae-sourced organic matter, whereas Type II oil and gas kerogen is present in both lignites and shales. Type III gas-prone kerogen is found only in shale. Genetic potential of 106.95 kgHC/t) in lignites and 20.87 kgHC/t in shales indicate excellent and moderate oil and gas potentials. All the source rocks are immature at the current outcrop positions but could have possibly attained maturity in the deeper subsurface area of the basin and contributed to the petroleum systems in the Anambra Basins. Ogwashi-Asaba formation has similar source rocks and organic matter types with the ones generating mixed marine and terrestrial oil within Agbada Formation, in the Niger Delta Basin. These source rocks are significant Oligocene-Miocene conventional and unconventional hydrocarbon resources depending on their current depth in the rift basins in West and Central Africa.

Organic Matter Distribution and Characteristics among Rock Formations in Malaysia: Implications on Hydrocarbon Generation Potential

Numerous studies have been done to determine the hydrocarbon potential of Malaysia’s formations and basins due to the need to identify more conventional or unconventional hydrocarbon resources. Due to the fact that none of these investigations were carried out with any prior knowledge in the relevant regions with hydrocarbon potential, some of them did not, however, yield the expected results. This study aims to provide researchers with all the necessary information about potential hydrocarbon-producing areas in Malaysia and the various lithologies connected to them by analyzing all earlier studies carried out in Malaysia. This was accomplished by determining patterns in the distribution of organic matter and characteristics of the formations in Malaysia. Total Organic Carbon (TOC), Generic Potential (GP), Vitrinite Reflectance (Ro), and Hydrocarbon Yield (S2) were the most important hydrocarbon generation potential indicators discussed. A heat map was created using a statistical weight ranking with a weight of 45% for the TOC value and 30%, 15%, and 10% for the GP, S2, and Ro values, respectively. According to the data, the Bintulu, Pinangah, Begrih, Liang, and Tanjong formations have the highest potential to generate hydrocarbons in Malaysia, while the Kroh, Setap, Kalabakan, Temburong, and Belaga have the least potential. Majority of formations with high hydrocarbon potential are tertiary in age and consist primarily of coal and carbonaceous shale formations. The most promising formations are mostly immature, with type II or type III kerogen quality. It is recommended that critical exploration activities be focused on the tertiary-aged formations, particularly those in East Malaysia, in order to increase Malaysia’s hydrocarbon production.

Critical Minerals for Zero-Emission Transportation.

Fundamentals of critical minerals and their paramount role in the successful deployment of clean energy technologies in future transportation are assessed along with current global efforts to satisfy the needs of automotive supply chains and environmental concerns. An implementation of large quantities of minerals, in particular metals, into the manufacturing of strategic components of zero-emission vehicles will bring new challenges to energy security. As a result, a reduced dependency on conventional hydrocarbon resources may lead to new and unexpected interdependencies, including dependencies on raw materials. It is concluded that to minimize the impact of a metal-intensive transition to clean transportation, in addition to overcoming challenges with minerals mining and processing, further progress in understanding the properties of critical materials will be required to better correlate them with intended applications, to identify potential substitutions and to optimize their use through the sustainable exploration of their resources and a circular economy.

Concurrent 17. Presentation for: Petroleum supersystems in the greater McArthur Basin, Northern Territory, Australia: prospectivity of the world’s oldest stacked systems with emphasis on the McArthur Supersystem

Presented on Wednesday 18 May: Session 17 This study assesses the prospectivity of the world’s oldest known stacked petroleum systems from the Proterozoic greater McArthur Basin (Northern Territory, Australia), which has immense potential to host both conventional natural gas and oil, in addition to shale-gas accumulations. The Mesoproterozoic succession of the Beetaloo Sub-basin and surrounding region hosts the Territory’s premier shale-gas play and is at an advanced stage of exploration for shale hydrocarbon plays. However, there is also potential for natural gas in older sedimentary packages, with flows and shows reported in underlying Paleoproterozoic successions. At the continent-scale, four regional petroleum supersystems are identified and described in order to provide a platform for consistent nomenclature at the sedimentary package and group level; in ascending stratigraphic order; these are the Paleoproterozoic Redbank and McArthur supersystems, the Paleoproterozoic–Mesoproterozoic Lawn Supersystem, and the Mesoproterozoic Beetaloo Supersystem. The Redbank and Lawn supersystems are newly named and defined, and the Beetaloo Supersystem is renamed from the former Urapungan Supersystem. Eight possible conventional natural gas plays and six shale-gas plays are documented within the McArthur Supersystem, which incorporates Glyde Package successions of the McArthur Basin and the Birrindudu Basin. Petroleum play concepts are also described from this supersystem to assist with assessing the potential for gas resources. A better understanding of the petroleum systems of the greater McArthur Basin is critical to the targeting of areas for geoscience data acquisition in order to facilitate the reduction of exploration search space; and it enables a more rigorous assessment of the potential for conventional and unconventional hydrocarbon resources at local (play) and regional scales. To access the presentation click the link on the right. To read the full paper click here

Characterization of Wax Precipitation and Deposition Behavior of Condensate Oil in Wellbore: A Comprehensive Review of Modeling, Experiment, and Molecular Dynamics Simulation

Condensate oil is increasingly valued as the high-quality conventional hydrocarbon resources generally decline. The efficient development of condensate oil, however, has always been a world problem; massive condensate oil will be retained in reservoirs in case of improper exploitation process, resulting in a significant resource waste and economic loss. One of the problems closely related to enhancing condensate oil recovery is wax precipitation and deposition in wellbore. Therefore, it is vital to investigate the characterization methods for the wax precipitation and deposition behavior in wellbores. The current status of research on modelling characterization methods, experimental characterization methods and molecular dynamics representation of wax precipitation and deposition behavior is reviewed in this paper; the applicability and limitation of modeling and experiment studies for characterizing wax precipitation and deposition of condensate oil in the wellbore are critically summarized and discussed. Moreover, the molecular dynamics simulation technique characterizes wax precipitation and deposition behavior from the micro scale, which makes up for the deficiencies of macroscopic experiment, enriches the investigation of wax precipitation and deposition, and provides important guidance and reference value for the development of unconventional hydrocarbon exploitation processes.

Petroleum supersystems in the greater McArthur Basin, Northern Territory, Australia: prospectivity of the world’s oldest stacked systems with emphasis on the McArthur Supersystem

This study assesses the prospectivity of the world’s oldest known stacked petroleum systems from the Proterozoic greater McArthur Basin (Northern Territory, Australia), which has immense potential to host both conventional natural gas and oil, in addition to shale-gas accumulations. The Mesoproterozoic succession of the Beetaloo Sub-basin and surrounding region hosts the Territory’s premier shale-gas play and is at an advanced stage of exploration for shale hydrocarbon plays. However, there is also potential for natural gas in older sedimentary packages, with flows and shows reported in underlying Paleoproterozoic successions. At the continent-scale, four regional petroleum supersystems are identified and described in order to provide a platform for consistent nomenclature at the sedimentary package and group level; in ascending stratigraphic order; these are the Paleoproterozoic Redbank and McArthur supersystems, the Paleoproterozoic–Mesoproterozoic Lawn Supersystem, and the Mesoproterozoic Beetaloo Supersystem. The Redbank and Lawn supersystems are newly named and defined, and the Beetaloo Supersystem is renamed from the former Urapungan Supersystem. Eight possible conventional natural gas plays and six shale-gas plays are documented within the McArthur Supersystem, which incorporates Glyde Package successions of the McArthur Basin and the Birrindudu Basin. Petroleum play concepts are also described from this supersystem to assist with assessing the potential for gas resources. A better understanding of the petroleum systems of the greater McArthur Basin is critical to the targeting of areas for geoscience data acquisition in order to facilitate the reduction of exploration search space; and it enables a more rigorous assessment of the potential for conventional and unconventional hydrocarbon resources at local (play) and regional scales.

Characteristics of the tuffaceous shale oil reservoir and its sweet spots: A case study of the Tiaohu depression in the Santanghu Basin

Shale oil has become an important alternative resource for conventional hydrocarbon resources. There are many areas with great exploration potential for shale oil worldwide, but the degree of exploration is relatively low. This study focuses on the shale oil reservoirs in the Tiaohu Depression of Santanghu Basin, northeast of Xinjiang Uygur Autonomous Region, China. We used pore permeability with 50 samples of saturation, thin section identification, high-pressure mercury injection, low-temperature nitrogen adsorption, and scanning electron microscopy (SEM), and according to these measurement technologies, we found that the study area is mainly composed of a set of basic-moderate volcaniclastic sediment; the shale reservoir is dense, with higher oil saturation; the fracture development zone is a movable desert area; and tuffaceous secondary pore formation is the main object of dissolution. It contains a variety of reservoir spaces, which are conducive to shale oil enrichment. The reservoir characteristics, microscopic pore structure, and origins of geological sweet spots are systematically analyzed, which provides research direction for shale oil exploration.

A zero emission scheme for producing energy from natural gas hydrates and conventional natural gas

The global amount of energy contained in natural gas hydrates is huge, maybe as much as twice all known conventional fossil fuel resources. Unlike the worldwide distribution of conventional fossil fuels, hydrocarbons trapped in water as hydrate is also available in countries with limited conventional hydrocarbon resources. The development towards lower global emissions of greenhouse gases requires new strategies for the use of hydrocarbons, whether they are available as conventional resources, or in the form of natural gas hydrates. In this work we outline some possible strategies of utilizing hydrocarbon energy resources in a clean and environmentally friendly way. The use of carbon dioxide for producing hydrates is not new. Results from several experimental studies are available. In this work we shed more light on thermodynamic limitations and the need for additives in order to make the approach technically efficient. Through thermodynamic analysis we show that up to 20 mol per cent N2 is feasible in a CO2/N2 injection gas based on ability to form a new hydrate with free pore water and the released enthalpy needed to dissociate in situ CH4 hydrate. Surfactant is also needed in order to keep the injection gas front free of blocking hydrate films. Small alcohols like methanol and ethanol have surfactant properties. It is demonstrated that even 10 wt% ethanol in liquid pore water still makes it feasible to create a new hydrate from injection gas containing 20 mol per cent N2. Consequences of other components than CH4 in the hydrate are also discussed. And in practical cases with a well-defined source of CO2 it is also important to investigate impact of other components like for instance H2S on the stability of injection gas hydrate, as well as changes in enthalpy of hydrate formation. Another key element of this work is the conversion of produced hydrocarbons over to hydrogen and carbon dioxide using steam cracking. The technology for this is very old and in daily use.

Conventional and Unconventional Hydrocarbon Resource Potential Evaluation of Source Rocks and Reservoirs: A Case Study of the Upper Xiaganchaigou Formation, Western Qaidam Basin, Northwest China

Conventional and Unconventional Hydrocarbon Resource Potential Evaluation of Source Rocks and Reservoirs: A Case Study of the Upper Xiaganchaigou Formation, Western Qaidam Basin, Northwest China

Prospects and Obstacles for Green Hydrogen Production in Russia

Renewable energy is considered the one of the most promising solutions to meet sustainable development goals in terms of climate change mitigation. Today, we face the problem of further scaling up renewable energy infrastructure, which requires the creation of reliable energy storages, environmentally friendly carriers, like hydrogen, and competitive international markets. These issues provoke the involvement of resource-based countries in the energy transition, which is questionable in terms of economic efficiency, compared to conventional hydrocarbon resources. To shed a light on the possible efficiency of green hydrogen production in such countries, this study is aimed at: (1) comparing key Russian trends of green hydrogen development with global trends, (2) presenting strategic scenarios for the Russian energy sector development, (3) presenting a case study of Russian hydrogen energy project «Dyakov Ust-Srednekanskaya HPP» in Magadan region. We argue that without significant changes in strategic planning and without focus on sustainable solutions support, the further development of Russian power industry will be halted in a conservative scenario with the limited presence of innovative solutions in renewable energy industries. Our case study showed that despite the closeness to Japan hydrogen market, economic efficiency is on the edge of zero, with payback period around 17 years. The decrease in project capacity below 543.6 MW will immediately lead to a negative NPV. The key reason for that is the low average market price of hydrogen ($14/kg), which is only a bit higher than its production cost ($12.5/kg), while transportation requires about $0.96/kg more. Despite the discouraging results, it should be taken into account that such strategic projects are at the edge of energy development. We see them as an opportunity to lead transnational energy trade of green hydrogen, which could be competitive in the medium term, especially with state support.