Unconventional Resources最新文献

The exploration of sweet spots in the Jimsar shale oil reservoir in Xinjiang involves creating a complex fracture network through three-dimensional well networks and advanced fracturing technology, crucial for successful shale oil reservoir development. However, the extremely low permeability of shale oil and limited natural flow capacity of crude oil pose significant challenges. The interconnection between three-dimensional well networks and artificial fracture networks, and the relationship between fracturing parameters and fracture morphology, remain unclear. This study focuses on the P₂l₁²⁻² and P₂l₁²⁻³ layers of the Lucaogou Formation. Utilizing the Petrel geological engineering integrated platform and the Kinetix fracturing module, we conducted numerical simulations to explore coupled fracturing in different sweet spots, with a specific emphasis on well network and fracture network coupling. This study identified relevant optimized engineering parameters. Research findings indicate that, during single-well single-factor optimization, the viscosity optimization range for Class II reservoirs is smaller compared to Class I reservoirs. However, for other factors such as injection rate, liquid volume, proppant concentration, cluster count, etc., the optimization ranges are greater for Class II reservoirs than for Class I reservoirs. In the case of single-factor optimization for well networks, increasing well spacing leads to larger optimization ranges for proppant concentration and perforation numbers. Under the same well spacing, an alternating wellbore arrangement results in a smaller optimization range for proppant concentration but a larger range for perforation numbers compared to a directly opposite wellbore arrangement. Additionally, this paper summarizes the optimization ranges and provides relevant tables and figures, aiming to offer guidance for on-site construction.

Geomechanical and multiphase flow characteristics are essential in recovering oil from naturally fractured rocks during hydrocarbon production because of changes in pore pressure and tension within the rock. It is a well-established fact that the geomechanical and multiphase flow characteristics of fractured rocks are interdependent on each other. Evaluation of these characteristics, for hydrocarbons displaced by water in fractured rocks under external stress loading, is severely lacking in published literature. This study aims to develop a novel numerical framework for a fully coupled model of fractured rocks, taking into consideration the pore pressure and porous media discontinuity at the fracture-matrix interface, along with an expanded Darcy's equation. The fully coupled Finite Element Method (FEM) and Computational Fluid Dynamics (CFD) model developed in this study is shown to accurately predict geomechanical and multiphase flow behaviour at the fracture-matrix interface. The results show that as external stress loading on the fractured rock increases, the porosity and permeability of the rock matrix decrease, capillary pressure at the fracture-matrix interface decreases, and the relative permeability curves shift to the right, indicating a water-soaked fracture-matrix interface. The findings of this study can be used to develop innovative strategies for enhanced oil recovery from fractured rocks.

CO₂ capture, utilization, and storage (CCUS) is a strategic emerging technology that has undergone rapid development in recent years. CO₂-Enhanced oil recovery with CO₂ utilization and storage (CCUS-EOR) is currently the most practicable large-scale carbon reduction technology and has become a key tool for large-scale applications of CCUS. In the inceptive period, CCUS-EOR was targeted towards flooding, but has since been extensively adopted for industrialization. At present, CCUS-EOR is being developed for synergistic flooding and storage, and is expected to gradually transition to utilization in geological storage for supporting large-scale carbon reduction to achieve the goal of carbon neutrality. The primary mechanisms controlling CCUS-EOR differ for high-permeability, high-water-cut oil reservoirs; low-permeability oil reservoirs; extra-low permeability oil reservoirs; and tight and shale oil reservoirs. Therefore, identifying the main constraints in the CO₂ flooding process and formulating effective development strategies are necessary for maximizing both oil recovery and storage. In the geological storage of CO₂, attention must be paid to key factors such as the storage capacity, injectivity, and safety. The storage performance can be enhanced through methods such as synergistic CO₂-enhanced water recovery and CO₂ storage (CCS-EWR), as well as rapid carbon mineralization in basalt. Globally, CCUS projects have undergone rapid growth, with more than 90 % of operational projects led by or involving oil and gas companies. In China, CCUS-EOR is currently in the early stage of industrial application. The first million-ton CCUS project has recently been completed. China has great potential for CCUS-EOR. An advantage of CCUS-EOR is the early adoption to large-scale applications, while CO₂ storage in saline aquifers provides a foundation for promoting large-scale development. In the future, multiple CCUS-EOR clusters are expected to be established in the Bohai Bay Basin, Songliao Basin, Ordos Basin, Yangtze River Delta, and Pearl River Delta regions, which will drive high-quality development of CCUS applications in China.

Chinese

Library Classification Number TE341.

Document Code

A.

The Beijing area is abundant in geothermal resources, yet there has been limited research on the thermal properties of rocks and their influencing factors. This paper focuses on the thermal properties of sedimentary rocks in the region, conducting experimental analysis to investigate these properties and their influencing factors. The experiment involved collecting primary sedimentary rock outcrop samples from around Beijing, testing the thermophysical parameters of 48 samples using a Hot Disk thermal constant analyzer. By combining this data with the standard stratum profile and historical information about Beijing, the thermal conductivity of the formation was calculated using the harmonic mean method, allowing for an analysis of the thermal properties of primary sedimentary rocks in the study area. The results indicate that overall distribution of thermal conductivity for sedimentary rocks in the Beijing area ranges from 1.48 to 6.55 W/(m·K), while thermal diffusivity ranges from 0.76 × 10⁻⁶ to 4.04 × 10⁻⁶ m²/s, and specific heat distribution ranges from 0.57 to 2.52MJ/(m³·K). Furthermore, according to harmonic mean calculations, it was found that Jixian formation exhibits the highest thermal conductivity value, whereas Triassic formation displays the lowest. This study on the thermal properties of sedimentary rocks provides valuable insights for the geothermal field research in the Beijing area.

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.