Unconventional Resources最新文献

Organic pores provide the primary storage space for hydrocarbons in some unconventional plays. However, organic pore volume and pore size distribution data are not routinely collected due to time, labor, and cost. This work presents an efficient workflow for the estimation of organic pore volume in self-sourcing reservoirs using more routinely gathered mineral and geochemical data and machine learning methods. This approach provides comparable results to the analytical approach of using subcritical N₂ adsorption, but at significantly reduced cost. The Late Devonian Duvernay Formation of western Canada is used as an example to develop the workflow. This workflow should be adaptable to other locations.

This work utilized total organic carbon (TOC), Rock-Eval pyrolysis, and mineral data. Data processing was performed prior to modeling to improve prediction accuracy and precision. Specifically, data transformation, stratification, and stratified three-fold cross validation approaches are used to overcome limitations of small datasets and improve model optimization. Multilinear Regression and Random Forest modeling are benchmarked for prediction optimization. Ensuring that training datasets include end-member data is critical to increase the reliability of model generalization. Stepwise regression and factor significance are used to select important factors in the modeling, observing that not all available data are needed for a meaningful prediction.

The Lower Silurian Longmaxi Formation is the favorable target area for deep shale gas exploration and development in southeastern Sichuan Basin. Based on whole-rock X-ray diffraction analysis, scanning electron microscope, reservoir evolution thermal simulation experiment and nitrogen adsorption experiment, the diagenetic characteristics of deep shale reservoir in Longmaxi Formation were analyzed, and the reservoir pore evolution law was clarified. The results show that: ①The diagenetic minerals of the deep shale in the Longmaxi Formation are mainly quartz and clay minerals, with a small amount of carbonate minerals and feldspar. The primary inorganic pores are mainly controlled by mechanical compaction and cementation (quartz, carbonate, clay, pyrite). The organic pores are mainly controlled by the thermal maturity of organic matter, dissolution and later compaction. ②In the process of thermal simulation experiment, the organic pores of shale show a process of change from scratch, from small to large and then from large to small. Later, the organic matter is affected by compaction and graphitization, and the volume of micropores and mesopores begins to decrease. ③The shale pores of Longmaxi Formation have undergone several evolutionary stages. In the early stage of diagenesis, compaction caused a large number of inorganic pores to disappear. In the middle stage of diagenesis, kerogen hydrocarbon generation occupied pores, dissolution and cementation transformed pores. In the late diagenetic period, liquid hydrocarbon cracking gas and pressurization promote the development of organic pores.

The Amu Darya Basin accounts for one of the most abundant natural gas resources globally, it is the main gas supplier to the Central Asian natural gas pipeline. It also holds potential for the natural gas exploration and development. Within this basin, valuable Jurassic carbonate rocks and gypsum-salt-gas-bearing combinations are developed. These include the presalt transitional Middle and Lower Jurassic coal-bearing source rocks, which provide sufficient gas sources, and the Middle and Upper Jurassic reef-shoal carbonate and gypsum salts, forming an effective reservoir–caprock combination. The unique geological configuration forms optimal accumulation conditions for natural gas in the high-energy sedimentary-facies belt of the carbonate platform which controlled by the coal-bearing gas-generation center and large basement ancient uplift area. Large natural gas fields are mainly distributed in the presalt Jurassic carbonate rocks, driven by high-quality hydrocarbon-generation centers, ancient uplift backgrounds, and ultrathick gypsum-salt rocks. While large gas fields have been discovered in large structural traps at the center of the depressions, exploration potential is still remains in the vast area with a burial depth exceeding 4500 m. These make the basin a key area for further exploration. The Amu Darya Right Bank Block located in the northeast of the basin, which has seen 15 years of rapid and efficient exploration and development by PetroChina, has discovered three gas field groups, each contains 2 billion m³ of gas: the western intraplatform shoal, central gently sloping reef beach, and Eastern thrust structure, fracture-cave-type gas field groups. PetroChina has achieved a production capacity of 14 billion cubic meters. In response to the geological and developmental characteristics of the three gas field groups, tailored development strategies have been formulated. The strategies are based on the integrated concept of geological and developmental engineering. Optimization efforts have been made in well pattern deployment, including highly deviated wells, as well as the design of gas field pressurization engineering. In addition, comprehensive evaluations have been conducted, taking the stable production period, water-avoidance distance, and investment considerations into account. The efforts aim to support the project of transforming the Amu Darya River into a model for the efficient development of the “Belt and Road” energy cooperation project.

The electrification rate in sub-Saharan Africa, standing at 45% in 2018, is significantly lower when compared with global benchmarks. The 600 million individuals lacking access to electricity constitute over two-thirds of the worldwide aggregate of the population lacking electricity. Limitations of power grids have placed a disproportionate burden of the lack of energy access on rural populations. The cheapest approach to achieving universal electricity access in numerous regions seems to be rooted in renewable energy. The diminishing cost of small-scale solar photovoltaic technology for solar home systems and mini-grids is expected to play a pivotal role in facilitating the provision of affordable electric power to millions. This study aims to elucidate the techno-economic benefits of augmenting photovoltaic mini-grids with the overarching goal of advocating for the adoption of photovoltaic mini-grid solutions in rural electrification in Sub-Saharan Africa. Prior research endeavors on rural electrification and photovoltaic mini-grids were meticulously curated and examined, with some attention also given to assessing the feasibility of grid integration. The findings showed that grid extension is the most cost-effective means of electricity delivery within a limited proximity, contingent upon topographical considerations. However, beyond this limited zone, mini-grids have proven to be more apt for providing affordable electricity to clustered customer populations. But mini-grids are not without challenges. High initial cost of installation, intermittency of energy source, energy storage problems, grid integration challenges, are some of the identified problems of photovoltaic mini-grids. The way forward must begin with the mitigation of these challenges. Some of the highlighted solutions include implementation of advanced energy storage systems, the formulation of renewable energy policies geared towards enhancing affordability in rural settings, integration with smart grid technologies, and adherence to grid codes to ensure compliance.

Field development is an important part of natural resource utilization and exploration because it involves a systematic evaluation and optimization of a specific area. This study examines the geothermal field development in the Gandhar region of Gujarat, India. Gandhar for the past several decades has been a flourishing field for hydrocarbon extraction. However, as the world is dealing with environmental issues and the need to shift to cleaner and more sustainable energy sources, geothermal energy has emerged as a feasible and ecologically sound option. This study aims to understand the potential of regions in and around Gandhar as a prospective geothermal field of the west coast continental margin of India. Three primary disciplines namely geological, geochemical, and geophysical surveys are employed on the surface to assess the potential of Gandhar's geothermal resources. Geological assessments provide information about underlying geological formations, which might help to locate possible geothermal resources. The Deccan basement is a prominent source of magmatic heat, with a thermal gradient ranging from 1.29 to 1.87 W/K. This enhances Gandhar's geothermal potential by heating the underlying water in conjunction with radionuclides found in the Earth's core. The temperatures range from 60 to 80 °C according to Giggenbach triangle method. Gandhar's geothermal potential is further highlighted by the fact that its water is bicarbonate-rich, which connects it to possible subterranean aquifers. These results are verified by geophysical studies. Prospective geothermal reserves and four way closures can be found by as anomalies. Gravity survey reveal a doubly plunging antiform, with gravity high value of 5.4 and 5.3 mGa l respectively, which is corroborated by magnetic peaks of 58 and 56.2 nT Areas with higher conductivity are identified by resistivity studies, which also indicate possible fluid paths and geothermal reservoirs. The paper outlines a conceptual field development plan for the identified prospect. The basic infrastructure and the cost associated with it for field development is worked out. The cost of production/MWe of energy generation is also highlighted.

This study investigates the adsorption behavior of carbon dioxide in organic nanopores with different surface roughness. The nanopores are constructed by sinusoidally corrugating the graphite slit pore walls. By computing the density distributions, adsorption quantities and orientation of carbon dioxide under various pressure and roughness conditions, we elucidate the impacts of surface roughness on carbon dioxide adsorption in organic nanopores. The Langmuir-Freundlich adsorption model is utilized to fit the isotherms of CO₂ adsorption under three different roughness conditions. the results show that increasing surface roughness led to the increase in the adsorption of carbon dioxide, as the relative roughness increased from 0% to 12.92%, the average CO₂ adsorption capacity increased by 0.003 mmol/m². Both the adsorbed layer density and monolayer maximum adsorption capacity increased concurrently with escalating roughness. Moreover, carbon dioxide molecules preferentially aligned parallel to the rough organic surface within the adsorption layer, consistent with the smooth graphitic wall configuration. All simulations, observations, and calculations were performed through grand canonical Monte Carlo (GCMC) simulations. These findings provide insights into the influence of surface roughness on CO₂ adsorption, especially in organic nanopores, which has substantial implications for carbon capture and geological sequestration applications. The results could facilitate optimization of strategies for efficient, secure geological CO₂ storage.

In recent years, Shale gas has been the fastest-growing energy source in the world. In USA, shale gas now contributes to more than 60 % of natural gas supply. In China, annual shale gas production climbed to 800 Bcf (billion cubic feet) in 2021. However, drilling in shale has been a major challenge since the dawn of petroleum industry due to the reactive clay minerals.

This paper surveys the field cases of drilling fluids in major shale plays. OBM (oil based mud), formulated with diesel and low fraction of water phase, provides effective shale stability, excellent lubricity, and high rate of penetration (ROP). As a result, more than 70 % of shale gas wells have been drilled with OBM with very few reported cases of wellbore instability. WBM (water-based mud) is made of water and necessary chemical additives. WBM is less costly and more environment-friendly than OBM, however some shale wells drilled with WBM reported severe instability issues. Nevertheless, recent innovations in WBM lead to successes in drilling major shale plays. WBM has great potential in shale drilling and deserves more research and improvements.

Identifying fractures is important for optimizing recovery and enhancing oil recovery techniques. Identifying natural fractures using FMI and cores is expensive and unavailable for all wells. Therefore, predictive models based on conventional wireline logs are necessary. Extreme Gradient Boosting, Decision tree, Random Forest, Support Vector Machine, Feed Forward Neural Network, and Recurrent Neural Network were applied to identify natural fractures. This study uses well logs to develop a new Fracture Signature Function equation for determining natural fractures in the shale reservoir. This unsupervised approach requires no special image log to identify natural fractures. However, the class imbalance problem between the fracture and non-fractured zone often restricts the accuracy of the machine learning models, which require a predictive model not dependent upon the special logs and class imbalance problems in the prediction of fractured zones. Synthetic Minority Oversampling (SMOTE) and Random Oversampling (ROS) were applied to solve the class imbalance problem in the data. The results show that the machine learning models did not predict the fracture and non-fracture zones with acceptable accuracy even after applying SMOTE and ROS. Relative to all machine learning models, Random Forest predicted the results with the highest accuracy of 91 % and F1-Score of 17.6 %. The Fracture Signature Function (FSFn'') predicted the natural fractures with high accuracy except in zones with very complex borehole environments. A Forward Neural Network is more efficient in identifying fracture and non-fractured zones in imbalance class problems of the dataset. The Recurrent Neural Network's predictions were biased toward the major class related to the non-fractured zone of the studied interval. The newly developed equation can be used for natural fracture identification in drilling and production strategy design by using the easily available well-log data in class imbalanced conditions.

Mixed depositional reservoirs are widely distributed in Junggar Basin, NW China. These reservoirs are featured by complex lithology, ultra-low permeability and extremely heterogeneous pore structures that markedly impact field development efficiency. This study illustrated the distribution of lithological combinations within a single sand bar in the Middle Permian Lucaogou Formation, Jimsar Sag, Junggar Basin and revealed the diagenetic control on the reservoir quality of a single sand bar based on thin sections, scanning electron microscopy (SEM), helium porosity and air permeability measurement, pressure-controlled mercury injection (PMI), rate-controlled mercury injection (RMI), X-ray computed tomography (CT), and collected and published data. The results show that the heterogeneity of microscopic pore structures within a single sandbar is controlled by the distribution of various lithological combinations and different levels of diagenetic alteration. The results show that there are mainly three types of lithology developed in a single sand bar. The reservoir quality of dolomitic siltstone reservoirs is the best, followed by silty dolomite reservoirs. The reservoirs quality of dolomicrite reservoirs is the worst. Three main lithological combinations can be identified within a single sand bar. Controlled by climate, lake level fluctuation and provenance, lithological combination A, characterized by blended mixing of dolomitic siltstone, silty dolomite and dolomicrite, is mainly developed in the middle of single sand bar. Lithological combination B, characterized by saltatory mixing of interbedded dolomitic siltstone and dolomicrite, and lithological combination A developed on the side of the sand bar near the shallow lake, while lithological combination C with blended mixing of interbedded dolomitic siltstone and silty dolomite developed on the side near provenance. Strong compaction is the main factor of the decrease of reservoir quality of sand bar reservoirs. Carbonate cementation promotes the densification of reservoirs. The irregular flaky clay minerals lead to the exponential decline of permeability, and dissolution is the main kind of diagenesis to improve reservoir quality. The dolomitic siltstone reservoirs in the middle of a single sand bar have the best reservoir quality because the overlying dolomicrite layers resist compaction, resulted in a certain amount of primary pores remained. Besides, the dolomitic siltstone reservoirs are far from the sand-mudstone interfaces, which leads to the low carbonate cement content. Furthermore, abundant dissolution pores in dolomitic siltstone reservoirs improve the reservoir quality. These research results are crucial to reservoir evaluation and development in similar mixed depositional tight reservoirs.