Search Results (85)

In the global energy sector, water-bearing reservoir-typed gas storage accounts for about 30% of underground gas storage (UGS) reservoirs and is vital for natural gas storage, balancing gas consumption, and ensuring energy supply stability. However, when constructing the UGS in the M gas reservoir, selecting suitable areas poses a challenge due to the complicated gas–water distribution in the multi-layered water-bearing gas reservoir with a long production history. To address this issue and enhance energy storage efficiency, this study presents an integrated geomechanical-hydraulic assessment framework for choosing optimal UGS construction horizons in multi-layered water-bearing gas reservoirs. The horizons and sub-layers of the gas reservoir have been quantitatively assessed to filter out the favorable areas, considering both aspects of geological characteristics and production dynamics. Geologically, caprock-sealing capacity was assessed via rock properties, Shale Gouge Ratio (SGR), and transect breakthrough pressure. Dynamically, water invasion characteristics and the water–gas distribution pattern were analyzed. Based on both geological and dynamic assessment results, the favorable layers for UGS construction were selected. Then, a compositional numerical model was established to digitally simulate and validate the feasibility of constructing and operating the M UGS in the target layers. The results indicated the following: (1) The selected area has an SGR greater than 50%, and the caprock has a continuous lateral distribution with a thickness range from 53 to 78 m and a permeability of less than 0.05 mD. Within the operational pressure ranging from 8 MPa to 12.8 MPa, the mechanical properties of the caprock shale had no obvious changes after 1000 fatigue cycles, which demonstrated the good sealing capacity of the caprock. (2) The main water-producing formations were identified, and the sub-layers with inactive edge water and low levels of water intrusion were selected. After the comprehensive analysis, the I-2 and I-6 sub-layer in the M 8 block and M 14 block were selected as the target layers. The numerical simulation results indicated an effective working gas volume of 263 million cubic meters, demonstrating the significant potential of these layers for UGS construction and their positive impact on energy storage capacity and supply stability. Full article

To address the challenges of water coning and early water breakthrough commonly encountered during the development of bottom-water gas reservoirs, this study establishes a fully coupled numerical simulation model integrating a horizontal wellbore, inflow control device (ICD) screens, and a zonal water control system. A novel “dual inflow performance index” method is introduced for the first time, enabling separate calculation of the pressure drops induced by gas and water phases flowing through the ICDs, thereby improving the accuracy of pressure simulations throughout the production lifecycle. The model divides the entire production system into four physically distinct subsystems, the bottom-water gas reservoir, ICD screens, production compartments, and the horizontal wellbore, which are dynamically coupled through transient interflow exchange. Based on geological parameters from the SPE10 dataset, the model simulates realistic production scenarios. The results show that the proposed model accurately captures the time-dependent increase in ICD pressure drop as fluid properties evolve during production. Moreover, the zonal water control method outperforms the single ICD-based control strategy in water control performance, achieving a 23% reduction in cumulative water production. Additionally, the water control intensity of the ICD screens increases nonlinearly with the reduction in the number of openings. In highly heterogeneous reservoirs with significant permeability contrast, effective suppression of water coning can only be achieved by setting a minimal number of openings in the high-permeability compartments, resulting in up to a 15% reduction in cumulative water production. The timing of production compartment shutdown exerts a significant influence on water control performance. The optimal strategy is to first identify the water breakthrough point through unconstrained production simulation as production with all eight ICD screen openings fully open and then shut down the high-permeability production compartment around this critical time. This approach can suppress cumulative water production by up to 27%. Overall, the proposed model offers a practical and robust tool for optimizing completion design and water control strategies in complex bottom-water gas reservoirs. Full article

Carbon dioxide (CO₂) geosequestration is a critical technology for reducing greenhouse gas emissions, with shale caprocks, such as Opalinus Clay (OPA), serving as essential seals to prevent CO₂ leakage. This study employs computational fluid dynamics and finite element analysis to investigate the hydromechanical behavior of OPA during CO₂ injection, integrating qualitative and quantitative insights. Validated numerical models indicate that capillary forces are the most critical factor in determining the material’s reaction, with an entry capillary pressure of 2–6 MPa serving as a significant threshold for CO₂ breakthrough. The numbers show that increasing the stress loading from 5 to 30 MPa lowers permeability by 0.3–0.45% for every 5 MPa increase. Porosity, on the other hand, drops by 9.2–9.4% under the same conditions. The OPA is compacted, and axial displacements confirm numerical models with an error margin of less than 10%. Saturation analysis demonstrates that CO₂ penetration becomes stronger at higher injection pressures (8–12 MPa), although capillary barriers slow migration until critical pressures are reached. These results demonstrate how OPA’s geomechanical stability and fluid dynamics interact, indicating that it may be utilized as a caprock for CO₂ storage. The study provides valuable insights for enhancing injection techniques and assessing the safety of long-term storage. Full article

Lost circulation during drilling has significantly hindered the safe and efficient development of oil and gas resources. Supramolecular polymer gel–based lost circulation materials have shown significant potential for application due to their unique molecular structures and superior performance. Herein, a high–performance supramolecular polymer gel was developed, and the influence of reservoir conditions on the performance of the supramolecular polymer gel was investigated in detail. The results identified an optimal formulation for the preparation of supramolecular polymer gel comprising 15 wt% acrylamide, 3 wt% 2-acrylamide-2-methylpropanesulfonic acid, 2.6 wt% divinylbenzene, 5 wt% polyvinyl alcohol, 0.30 wt% cellulose nanofibers, and 3 wt% laponite. The performance of the gel-forming suspension and the resulting supramolecular polymer gel was influenced by various factors, including temperature, density, pH, and the intrusion of drilling fluid, saltwater, and crude oil. Nevertheless, the supramolecular polymer gels consistently exhibited high strength under diverse environmental conditions, as confirmed by rheological measurements. Moreover, the gels exhibited strong plugging performance across various fracture widths and in permeable formations, with maximum breakthrough pressures exceeding 6 MPa. These findings establish a theoretical foundation and practical approach for the field application of supramolecular polymer gels in complex geological formations, demonstrating their effectiveness in controlling lost circulation under challenging downhole conditions. Full article

To address the issue of sealing failure of cement materials commonly used as wellbore plugging agents in CO₂ geological storage, this study proposes a composite wellbore plugging method that combines cement and Sn58Bi alloy. In this method, a composite sealing structure of “cement–Sn58Bi alloy–cement” is constructed within the wellbore. To evaluate the performance of this method, a series of pressure-bearing and gas-tightness experimental devices were designed, and experiments were conducted to assess the pressure-bearing capacity and gas sealing performance of the composite plugs. Additionally, optical microscopy was employed to observe and analyze the microstructure of the plugs. The effects of alloy proportion and temperature on the sealing performance of the composite plugs were systematically investigated. The experimental results indicate that both the pressure-bearing capacity and gas-tightness performance of the plugs are influenced by the alloy content and ambient temperature. Specifically, when the temperature increased from 30 °C to 60 °C, the pressure-bearing capacity decreased by an average of 28.3%; when further increased from 60 °C to 90 °C, it decreased by an average of 21.1%. In contrast, the gas-tightness performance exhibited an opposite trend, with the breakthrough pressure increasing by an average of 25.7% and 22.0%, respectively, over the same temperature intervals. Moreover, increasing the alloy proportion in the composite plugs enhanced both their pressure-bearing and gas-tightness performances. This study provides theoretical support for the application of composite plugs in CO₂ geological storage. Full article

In order to analyze the explosion risk of the engine room, this paper uses CFD software to simulate the LNG leakage process in the engine room of the ship, and uses the combustible gas cloud obtained from the leakage simulation to simulate the explosion, analyzing its combustion and explosion dynamics. On the basis of previous studies, this paper studies the coupling of leakage and explosion simulation to ensure that it conforms to the real situation. At the same time, taking explosion overpressure, explosion temperature, and the mass fraction of combustion products as the breakthrough point, this paper studies the harm of explosion to human body and the influence of ignition source location on the propagation characteristics of LNG explosion shock wave in the engine room, and discusses the influence of obstacles on gas diffusion and accumulation. The results show that the LNG leakage reaches the maximum concentration in the injection direction, and the obstacles in the cabin have a significant effect on the diffusion and accumulation of gas. In the explosion simulation based on the leakage results, it can be determined that the shape of the pressure field generated by the explosion is irregular, and the pressure field at the obstacle side has obvious accumulation. Finally, in order to reduce the explosion hazard, the collaborative strategy of modular layout, directional ventilation, and gas detection is proposed, which provides ideas for the explosion-proof design of the cabin. Full article

The conceptual design and techno-economic assessment of Pressure Swing Adsorption (PSA) for the recovery of H₂, CO₂, and CO from steel making Blast Furnace-Basic Oxygen Furnace and Coke Oven off-gases, major contributors to anthropogenic carbon emissions, are presented. Three PSA units are modeled on Aspen Adsorption V14, each utilising dedicated adsorbents and configurations tailored for the target gas. Model validation is successfully conducted by comparing breakthrough simulation results with experimental data. The simulation results demonstrate that the PSA systems effectively separate H₂ (99.3% purity, 80% recovery), CO (98% purity, 87% recovery), and CO₂ (96.9% purity, 75% recovery) from steelmaking off-gases. Meanwhile, the techno-economic assessment indicates that the PSA systems are economically viable, with competitive costs of £2768/tH₂, £52.78/tCO, and £16.89/tCO₂ captured, making them an effective solution for gas separation in the steel industry. Full article

Tight sandstone gas reservoirs, characterized by low porosity (typically < 10%) and ultra-low permeability (commonly < 0.1 × 10⁻³ μm²), represent a critical transitional resource in global energy transition, accounting for over 60% of total natural gas production in regions such as North America and Canada. In the northern Tianhuan Depression of the Ordos Basin, the Permian He 8 Member (He is the abbreviation of Shihezi) of the Shihezi Formation serves as one of the primary gas-bearing intervals within such reservoirs. Dominated by quartz sandstones (82%) with subordinate lithic quartz sandstones (15%), these reservoirs exhibit pore systems primarily supported by high-purity quartz and rigid lithic fragments. Diagenetic processes reveal sequential cementation: early-stage quartz cementation provides a framework for subsequent lithic fragment cementation, collectively resisting compaction. Depositionally, these sandstones are associated with fluvial-channel environments, evidenced by a sand-to-mud ratio of ~5.2:1. Pore structures are dominated by intergranular pores (65%), followed by dissolution pores (25%) formed via selective leaching of unstable minerals by acidic fluids in hydrothermal settings, and minor intragranular pores (10%). Authigenic clay minerals, predominantly kaolinite (>70% of total clays), act as the main interstitial material. Reservoir properties average 7.01% porosity and 0.5 × 10⁻³ μm² permeability, defining a typical low-porosity, ultra-low-permeability system. Vertically stacked sand bodies in the He 8 Member display large single-layer thicknesses (5–12 m) and moderate sealing capacity (caprock breakthrough pressure > 8 MPa), hosting gas–water mixed-phase occurrences. Rock mechanics experiments demonstrate that fractures enhance permeability by >60%, significantly controlling reservoir heterogeneity. Full article

Hydrogen (H₂) is a key energy carrier and industrial feedstock, with growing interest in its production from syngas and water–gas shift (WGS) syngas. Effective purification methods are essential to ensure high hydrogen purity for various applications, particularly fuel cells, chemical synthesis, or automotive fuel. Pressure swing adsorption (PSA) has emerged as a dominant separation technology due to its efficiency, scalability, and industrial maturity. This study reviews PSA-based hydrogen purification and proposes an experimental framework based on literature insights. Key process variables influencing PSA performance, such as adsorbent selection, cycle sequences, pressure conditions, and flow configurations, are identified. The proposed experimental methodology includes breakthrough adsorption studies and PSA process evaluations under dynamic conditions, with variations in column configuration, adsorption pressure (8–9 bar), and process concept (Berlin and Linde Gas). The purpose of the review is to prepare for syngas separation by the selected process in terms of hydrogen recovery and purity using ITPE’s advanced technological facilities. The findings are expected to contribute to improving PSA-based hydrogen purification strategies, offering a pathway for enhanced industrial-scale hydrogen production. This work provides a foundation for bridging theoretical PSA principles with practical implementation, supporting the growing demand for clean hydrogen in sustainable energy systems. Full article

The CO₂ injection technology for replacing CH₄ to enhance coalbed methane (CBM) recovery (CO₂-ECBM) offers dual benefits, i.e., reducing CO₂ emissions through sequestration and increasing CBM recovery, thereby leading to economic gains. However, there is no clear consensus on how temperature and pressure affect the competitive adsorption characteristics of CO₂ and CH₄ mixed gases in coal. Therefore, the competitive adsorption behavior of CO₂ and CH₄ mixed gases at various pressures and temperatures were investigated using the breakthrough curve method. Anthracite was selected for the adsorption experiment conducted under three gas injection pressure levels (0.1 MPa, 0.5 MPa, and 1 MPa) and at three temperature levels (20 °C, 40 °C, and 60 °C). This study showed that, when the temperature remained constant and the pressure ranged from 0.1 to 1 MPa, the adsorption rates of CO₂ and CH₄ increased as pressure rose. Additionally, the selectivity coefficient for CO₂/CH₄ decreased with an increase in pressure, suggesting that higher pressures within this range are not conducive to the replacement efficiency of CH₄ by CO₂. As the temperature increased from 20 to 60 °C under constant pressure conditions, both the selectivity coefficients for CO₂/CH₄ and the adsorption rates of CO₂ and CH₄ exhibited a downward trend. These findings imply that, within this temperature range, a reduced temperature improves the ability of CO₂ to efficiently displace CH₄. Moreover, CO₂ exhibits a higher isosteric heat of adsorption compared to CH₄. Full article

High-pressure low-permeability gas reservoirs have a complex gas–water distribution, a lack of a unified gas–water interface, and widespread water intrusion in localized high areas, which seriously constrain sweet spot prediction and development deployment. In this study, the high-pressure, low-permeability sandstone of Huangliu Formation in Yinggehai Basin is taken as the object, and the micro gas–water distribution mechanism and the main controlling factors are revealed by combining core expulsion experiments and COMSOL two-phase flow simulations. The results show that the gas saturation of the numerical simulation (20 MPa, 68.98%) is in high agreement with the results of the core replacement (66.45%), and the reliability of the model is verified. The natural gas preferentially forms continuous seepage channels along the large pore throats (0.5–10 μm), while residual water is trapped in the small throats (<0.5 μm) and the edges of the large pore throats that are not rippled by the gas. The breakthrough mechanism of filling pressure grading shows that the gas can fill the 0.5–10 μm radius of the pore throat at 5 MPa, and above 16 MPa, it can enter a 0.01–0.5 μm small throat channel. The distribution of gas and water in the reservoir is mainly controlled by the pore throat structure, formation temperature, and filling pressure, and the gas–liquid interfacial tension and wettability have weak influences. This study provides a theoretical basis for the prediction of sweet spots and optimization of development plans for low-permeability gas reservoirs. Full article

The well-doublet production model has far-reaching implications for the sustainable utilization of geothermal resources. The position of the injection well in the geothermal production process is closely connected to the emergence of thermal breakthroughs and the production lifespan. Thus, it is necessary to optimize the well placement. However, traditional simulation and optimization approaches require a long time and have a high computing burden. In this paper, a surrogate model based on the back propagation neural network (BPNN) is trained to improve the drawbacks of previous approaches, and it is combined with the genetic algorithm (GA) to develop a simulation-optimization approach to find the optimal well placement of a well-doublet geothermal production system. To guarantee that the training data have appropriate physical significance, the TOUGH2 program is used for the hydro–thermal model development of the geothermal reservoir of the Minghuazhen Formation in Tianjin, China. A sensitivity analysis is used to select the series of samples used for training, which includes temperature and pressure variation, heat extraction rate (Wh), and economic cost. The results reveal that the surrogate model has excellent prediction accuracy and efficiency for physical processes, and the genetic algorithm optimization outcomes are consistent with predictions, which is of practical importance. Full article

To address the critical challenges of wellbore instability in deep coal seam drilling operations, this investigation developed an innovative organic–inorganic composite nanosealing agent (NS) through chemical modification of nano-silica. Advanced characterization techniques including Fourier Transform Infrared Spectroscopy, laser particle size analysis, and Scanning Electron Microscopy revealed that the optimized NS possessed a uniform particle distribution (mean diameter 86 nm) and enhanced surface hydrophobicity, effectively mitigating particle agglomeration. Systematic experimental evaluation demonstrated the material’s multifunctional performance: the NS-enriched drilling fluid achieved an 88.7% reduction in sand bed invasion depth and 76.4% decrease in filtrate loss at optimal concentration. Notably, comparative inhibition tests showed the NS outperformed conventional KCl and KPAM inhibitors, achieving 91.2% shale rolling recovery rate and 65.3% lower swelling rate than deionized water baseline. Core flooding experiments further confirmed superior sealing capability, with 2% NS addition attaining 88% sealing efficiency for low-permeability cores (0.5 mD) and establishing a 10 MPa breakthrough pressure threshold. Field implementation in the SSM1 well at Shenmu Huineng Liangshui Coal Mine validated the technical efficacy, the NS-enhanced drilling fluid system achieved 86.7% coal seam encounter rate with zero wellbore collapse incidents, while core recovery rate improved by 32.6% to 90.4% compared to conventional systems. This research breakthrough provides a scientific foundation for developing next-generation intelligent drilling fluids, demonstrating significant potential for ensuring drilling safety and enhancing gas recovery efficiency in deep coalbed methane reservoirs. Full article

CO₂-enhanced gas recovery (EGR) has emerged as a promising method for improving hydrocarbon production and achieving carbon sequestration in offshore gas reservoirs. This study investigates the performance and influencing factors of CO₂-based gas displacement using long core displacement experiments. Consolidated synthetic cores were prepared to replicate reservoir conditions, and experiments were conducted at formation pressure and temperature to evaluate the effects of permeability, injection pressure, CO₂ concentration, and core length on gas recovery efficiency. The results reveal that (1) for a homogeneous porous medium, permeability and injection pressure have minimal correlation with recovery efficiency when sufficient gas is injected; (2) direct gas displacement after reservoir depletion outperforms pressure-boosting displacement methods; (3) higher CO₂ concentrations delay gas breakthrough, enhance piston-like displacement behavior, and improve recovery efficiency; and (4) core length significantly affects recovery, with longer cores resulting in slower breakthroughs and more stable displacement. Cores of at least 1 m in length are essential for accurately simulating field conditions. For a CO₂ injection with a pressure of 7 MPa and a temperature of 81 °C, when 0.87 PV of CO₂ is injected, the current recovery can reach 87%, after which the displacement efficiency decreases sharply. The ultimate EGR can be as high as 50%. These findings provide valuable insights into optimizing CO₂ injection strategies for enhanced gas recovery in offshore reservoirs, offering guidance for both experimental designs and practical applications in the field. Full article

As global energy demand continues to grow, the difficulty and cost of extracting oil and gas resources are gradually increasing, making enhanced oil recovery (EOR) one of the key issues in oil and gas field development. CO₂ flooding, as an effective tertiary oil recovery technique, has significant advantages in improving recovery rates due to its ability to significantly reduce crude oil viscosity, increase formation energy, and expand the swept volume. However, the effectiveness of CO₂ flooding is influenced by various factors, including flooding methods, well patterns, and formation parameters. In this study, a two-dimensional high-temperature and high-pressure simulation device was used to simulate the CO₂ flooding process under various flooding methods, including water flooding followed by continuous gas flooding, water–gas alternating flooding, and foam flooding, for two types of injection–production well patterns based on the formation oil parameters of the Hei 125 block in the Daqingzijing Oilfield. The results indicate that during the transition from water flooding to continuous gas flooding, gas breakthrough channels form rapidly, leading to a rapid increase in the produced gas–oil ratio (GOR). Alternatively, alternating injection of gas and liquid can effectively control gas mobility, reduce gas phase permeability, delay gas breakthrough time, and improve oil displacement efficiency. Water–gas alternating flooding forms water–gas slugs, allowing CO₂ to enter the tiny pores to contact crude oil, reducing resistance in the pores, and enhancing crude oil displacement efficiency. Although the foam system can expand the fluid sweep range, excessive gas injection can lead to premature gas breakthrough. Furthermore, the type of injection–production well pattern has a significant impact on the overall reservoir recovery for foam system and gas alternating flooding with a 1:1 ratio; adjusting the well pattern can increase the sweep efficiency and improve ultimate recovery. This study reveals the mechanisms by which different flooding methods and well patterns affect the effectiveness of CO₂ flooding, providing important theoretical and practical guidance for optimizing flooding strategies and improving oil recovery in oil and gas fields. It is of great significance for promoting the application of CO₂ flooding technology in oil and gas field development. Full article