Search Results (161)

The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones in their pore structure, permeability, water saturation, and pressure sensitivity, significant variations exist in their flow capacities and fluid production behaviors. To address the challenges of production allocation and main reservoir identification in the co-development of CBM and tight gas within deep gas-bearing basins, this study employs the transient multiphase flow simulation software OLGA to construct a representative dual-gas co-production well model. The regulatory mechanisms of the gas–liquid distribution, deliquification efficiency, and interlayer interference under two typical vertical stacking relationships—“coal over sand” and “sand over coal”—are systematically analyzed with respect to different tubing setting depths. A high-precision dynamic production allocation method is proposed, which couples the wellbore structure with real-time monitoring parameters. The results demonstrate that positioning the tubing near the bottom of both reservoirs significantly enhances the deliquification efficiency and bottomhole pressure differential, reduces the liquid holdup in the wellbore, and improves the synergistic productivity of the dual-reservoirs, achieving optimal drainage and production performance. Building upon this, a physically constrained model integrating real-time monitoring data—such as the gas and liquid production from tubing and casing, wellhead pressures, and other parameters—is established. Specifically, the model is built upon fundamental physical constraints, including mass conservation and the pressure equilibrium, to logically model the flow paths and phase distribution behaviors of the gas–liquid two-phase flow. This enables the accurate derivation of the respective contributions of each reservoir interval and dynamic production allocation without the need for downhole logging. Validation results show that the proposed method reliably reconstructs reservoir contribution rates under various operational conditions and wellbore configurations. Through a comparison of calculated and simulated results, the maximum relative error occurs during abrupt changes in the production capacity, approximately 6.37%, while for most time periods, the error remains within 1%, with an average error of 0.49% throughout the process. These results substantially improve the timeliness and accuracy of the reservoir identification. This study offers a novel approach for the co-optimization of complex multi-reservoir gas fields, enriching the theoretical framework of dual-gas co-production and providing technically adaptive solutions and engineering guidance for multilayer unconventional gas exploitation. Full article

The development of deep coalbed methane (buried depth > 2000 m) in the Yan’an block of Ordos Basin is limited by low permeability, the pore structure of the coal reservoir, and the gas–water occurrence relationship. It is urgent to clarify the key control mechanism of pore structure on gas migration. In this study, based on high-pressure mercury intrusion (pore size > 50 nm), low-temperature N₂/CO₂ adsorption (0.38–50 nm), low-field nuclear magnetic resonance technology, fractal theory and Pearson correlation coefficient analysis, quantitative characterization of multi-scale pore–fluid system was carried out. The results show that the multi-scale pore network in the study area jointly regulates the occurrence and migration process of deep coalbed methane in Yan’an through the ternary hierarchical gas control mechanism of ‘micropore adsorption dominant, mesopore diffusion connection and macroporous seepage bottleneck’. The fractal dimensions of micropores and seepage are between 2.17–2.29 and 2.46–2.58, respectively. The shape of micropores is relatively regular, the complexity of micropore structure is low, and the confined space is mainly slit-like or ink bottle-like. The pore-throat network structure is relatively homogeneous, the difference in pore throat size is reduced, and the seepage pore shape is simple. The bimodal structure of low-field nuclear magnetic resonance shows that the bound fluid is related to the development of micropores, and the fluid mobility mainly depends on the seepage pores. Pearson’s correlation coefficient showed that the specific surface area of micropores was strongly positively correlated with methane adsorption capacity, and the nanoscale pore-size dominated gas occurrence through van der Waals force physical adsorption. The specific surface area of mesopores is significantly positively correlated with the tortuosity. The roughness and branch structure of the inner surface of the channel lead to the extension of the migration path and the inhibition of methane diffusion efficiency. Seepage porosity is linearly correlated with gas permeability, and the scale of connected seepage pores dominates the seepage capacity of reservoirs. This study reveals the pore structure and ternary grading synergistic gas control mechanism of deep coal reservoirs in the Yan’an Block, which provides a theoretical basis for the development of deep coalbed methane. Full article

With growing reliance on hydraulic fracturing to develop tight oil and gas reservoirs characterized by low porosity and permeability, optimizing proppant transport and placement has become critical to sustaining fracture conductivity and production. However, how fracture geometry influences proppant distribution under varying field conditions remains insufficiently understood. This study employed computational fluid dynamics to investigate proppant transport and placement in hydraulic fractures of which the aperture tapers linearly along their length. Four taper rate models (δ = 0, 1/1500, 1/750, and 1/500) were analyzed under a range of operational parameters: injection velocities (1.38–3.24 m/s), sand concentrations (2–8%), proppant particle sizes (0.21–0.85 mm), and proppant densities (1760–3200 kg/m³). Equilibrium proppant pack height was adopted as the key metric for pack morphology. The results show that increasing injection rate and taper rate both serve to lower pack heights and enhance downstream transport, while a higher sand concentration, larger particle size, and greater density tend to raise pack heights and promote more stable pack geometries. In tapering fractures, higher δ values amplify flow acceleration and turbulence, yielding flatter, “table-top” proppant distributions and extended placement lengths. Fine, low-density proppants more readily penetrate to the fracture tip, whereas coarse or dense particles form taller inlet packs but can still be carried farther under high taper conditions. These findings offer quantitative guidance for optimizing fracture geometry, injection parameters, and proppant design to improve conductivity and reduce sand-plugging risk in tight formations. These insights address the challenge of achieving effective proppant placement in complex fractures and provide quantitative guidance for tailoring fracture geometry, injection parameters, and proppant properties to improve conductivity and mitigate sand plugging risks in tight formations. Full article

This article provides a comprehensive review of gas flow behavior in low-permeability geological media, focusing on its implications for the long-term performance of engineered barriers in underground radioactive waste repositories. Key mechanisms include two-phase flow and gas-driven fracturing, both critical for assessing repository safety. Understanding the generation and migration of gas is crucial for the quantitative assessment of repository performance over extended timescales. The article synthesizes the current research on various types of claystone considered as potential host rocks for repositories, providing a comprehensive analysis of gas transport mechanisms and constitutive models. In addressing the challenges related to multi-field coupling, the article provides practical insights and outlines potential solutions and areas for further research, underscoring the importance of interdisciplinary collaboration to tackle these challenges and push the field forward. In addition, the article evaluates key research projects, such as GMT, FORGE, and DECOVALEX, shedding light on their methodologies, findings, and significant contributions to understanding gas migration in low-permeability geological media. In this context, mathematical modeling becomes indispensable for predicting long-term repository performance under hypothetical future conditions, enhancing prediction accuracy and supporting long-term safety assessments. Finally, the growing interest in gas-driven fracturing is explored, critically assessing the strengths and limitations of current numerical simulation tools, such as TOUGH, the phase-field method, and CODE_BRIGHT. Noteworthy advancements by the CODE_BRIGHT team in gas injection simulation are highlighted, although knowledge gaps remain. The article concludes with a call for innovative approaches to simulate gas fracturing processes more effectively, advocating for advanced modeling techniques and rigorous experimental validation to address existing challenges. Full article

Unconventional hydrocarbon reservoirs with low matrix permeability (<0.3 mD), high temperatures, and sour conditions present significant challenges for stimulation and production enhancement. This study examines field trials for a large oil and gas operator in the UAE, focusing on tight carbonate deposits with reservoir temperatures above 93 °C and high sour gas content. A novel multi-stage chemical stimulation workflow was created, beginning with a pre-flush phase that alters rock wettability and reduces interfacial tension at the micro-scale. This was followed by a second phase that increased near-wellbore permeability and ensured proper acid placement. The treatment’s core used a thermally stable, corrosion-resistant retarded acid system designed to slow reaction rates, allow deeper acid penetration, and build prolonged conductive wormholes. Simulations revealed considerable acid penetration of the formation beyond the near-wellbore zone. The post-treatment field data showed a tenfold improvement in injectivity, which corresponded closely to the acid penetration profiles predicted by modeling. Furthermore, oil production demonstrated sustained, high oil production of 515 bpd on average for several months after the treatment, in contrast to the previously unstable and low-rate production. Finally, the findings support a reproducible and technologically advanced stimulation technique for boosting recovery in ultra-tight carbonate reservoirs using the acid retardation effect where traditional stimulation fails. Full article

Pulsed Power Plasma Stimulation (3PS) represents a promising and environmentally favorable alternative to conventional well stimulation techniques for enhancing subsurface permeability. This comprehensive review tracks the evolution of plasma-based rock stimulation, offering insights from key laboratory, numerical, and field-scale studies. The review begins with foundational electrohydraulic discharge concepts and progresses through the evolution of Pulsed Arc Electrohydraulic Discharge (PAED) and the more advanced 3PS systems. High-voltage, ultrafast plasma discharges generate mechanical shockwaves and localized thermal effects that result in complex fracture networks, particularly in tight and crystalline formations. Compared to conventional well stimulation techniques, 3PS reduces water use, avoids chemical additives, and minimizes induced seismicity. Laboratory studies demonstrate significant improvements in permeability, porosity, and fracture intensity, while field trials show an increase in production from oil, gas, and geothermal wells. However, 3PS faces some limitations such as short stimulation radii and logistical constraints in wireline-based delivery systems. Emerging technologies like plasma-assisted drilling and hybrid PDC–plasma tools offer promising integration pathways. Overall, 3PS provides a practical, scalable, low-impact stimulation approach with broad applicability across energy sectors, especially in environmentally sensitive or water-scarce regions. Full article

Coalbed methane (CBM), a significant unconventional natural gas resource, holds a crucial position in China’s ongoing energy structure transformation. However, the inherent low permeability, high brittleness, and strong sensitivity of CBM reservoirs to drilling fluids often lead to severe formation damage during drilling operations, consequently impairing well productivity. To address these challenges, this study developed a novel low-damage, plugging, and anti-collapse water-based drilling fluid gel system (ACWD) specifically designed for coalbed methane drilling. Laboratory investigations demonstrate that the ACWD system exhibits superior overall performance. It exhibits stable rheological properties, with an initial API filtrate loss of 1.0 mL and a high-temperature, high-pressure (HTHP) filtrate loss of 4.4 mL after 16 h of hot rolling at 120 °C. It also demonstrates excellent static settling stability. The system effectively inhibits the hydration and swelling of clay and coal, significantly reducing the linear expansion of bentonite from 5.42 mm (in deionized water) to 1.05 mm, and achieving high shale rolling recovery rates (both exceeding 80%). Crucially, the ACWD system exhibits exceptional plugging performance, completely sealing simulated 400 µm fractures with zero filtrate loss at 5 MPa pressure. It also significantly reduces core damage, with an LS-C1 core damage rate of 7.73%, substantially lower than the 19.85% recorded for the control polymer system (LS-C2 core). Field application in the JX-1 well of the Ordos Basin further validated the system’s effectiveness in mitigating fluid loss, preventing wellbore instability, and enhancing drilling efficiency in complex coal formations. This study offers a promising, relatively environmentally friendly, and cost-effective drilling fluid solution for the safe and efficient development of coalbed methane resources. Full article

The distribution of leachate in landfill systems significantly influences landfill stability, pollutant migration, and gas transport. However, existing methods for measuring leachate levels in landfills with multiple intermediate cover layers remain insufficient. This study introduces a novel in situ testing method to determine multi-layer leachate levels. Field experiments at a landfill site in northwestern China successfully quantified leachate levels on each intermediate cover layer. Seepage analysis simulated the leachate level recovery test method used in field investigations, enabling examination of the formation mechanisms and drainage characteristics of multi-layer leachate systems. Measurement results demonstrated that each intermediate cover layer retained a corresponding perched leachate level. Variations in perched water head across waste layers arise from differences in drainage capacity between waste strata. Differential settlement of the intermediate cover layers in localized areas generated adverse hydraulic gradients, contributing to spatial heterogeneity in perched leachate distribution. Back analysis yields an in situ saturated hydraulic conductivity ranging from 1 × 10⁻⁴ to 3.3 × 10⁻³ cm/s. Low-permeability intermediate cover layers were identified as the primary factors contributing to multi-layer leachate formation. The implementation of effective horizontal drainage can reduce perched leachate accumulation above intermediate layers. Full article

With the aim of the limitations of the existing hydroelectric simulation experiment methods under non-homogeneous reservoir conditions, this paper investigates the seepage characteristics and production capacity laws of complex structural wells by designing hydroelectric simulation experiments of horizontal wells and planar multi-branch wells under non-homogeneous reservoir conditions, based on the hydroelectric similarity principle. The experiments use a CuSO₄ solution and gel to simulate homogeneous and non-homogeneous reservoirs, respectively, and combine with similarity theory to construct the correspondence between the seepage field and the electric field, and to analyze the pressure distribution and the change in production. The results show the following: non-homogeneity significantly alters seepage paths, leading to a reduction in the actual control area; the superimposed effects of branching interference of planar multi-branching wells, and the non-homogeneity of the reservoir, increase the effectiveness of mobilizing the low-permeability area between the branches; the daily gas production of the horizontal wells and the planar multi-branching wells under non-homogeneous conditions are 37.6 × 10⁴ m³/d and 70.9 × 10⁴ m³/d, respectively; and the production gap widened with the increase in the pressure function difference as compared to the homogeneous conditions. This study provides an experimental basis for the development of non-homogeneous gas reservoirs, and it has reference value for the study of seepage mechanism and optimization of well design. Full article

The Dolomite reservoir of the Maokou Formation is rich in gas resources in the central Sichuan Basin. Acid fracturing is an important technical means to improve reservoir permeability and productivity. The interaction mode of the dolomite and limestone acid system will affect the effect of reservoir reconstruction. In order to clarify the influence of complex structure on fracture morphology, we explore the fracturing effect of different acid systems. Physical simulation experiments of true triaxial acid fracturing were carried out with two acid systems and downhole full-diameter cores. The experimental results show: (1) After the carbonate rock is subjected to acid fracturing using a “self-generated acid + gel acid” system, the fracture pressure drops significantly by up to 60%. The morphology of the acid-eroded fractures becomes more complex, with an increase in geometric complexity of about 28% compared to a single acid solution system. It is prone to form three-dimensional “spoon” shaped fractures, and the surface of the acid-eroded fractures shows light yellow acid erosion marks. Analysis of the acid erosion marks indicates that the erosion depth on the fracture surface reaches 0.8–1.2 mm, which is deeper than the 0.2 mm erosion depth achieved with a single system. (2) Acid solution is difficult to penetrate randomly distributed calcite veins with a low porosity and permeability structure. When the fracture meets the calcite vein, the penetration rate of acid solution drops sharply to 15–20% of the initial value, resulting in a reduction of about 62% of the acid erosion area in the limestone section behind. And the acid erosion traces in the limestone behind the calcite vein are significantly reduced. The acid erosion cracks are easy to open on the weak surface between dolomite and limestone, causing the fracture to turn. (3) The results of field engineering and experiment are consistent, and injecting authigenic acid first in the process of reservoir reconstruction is helpful to remove pollution. The recovery rate of near-well permeability is more than 85% with pre-generated acid. Reinjection of gelled acid can effectively communicate the natural weak surface and increase the complexity of cracks. The average daily oil production of the completed well was increased from 7.8 m³ to 22.5 m³, and the increase factor reached 2.88. Full article

In this article, we consider the roles of transcrustal magma- and fluid-conducting faults (TCMFCFs) in the formation of mineral deposits, showing the importance of deep sources of heat and hydrothermal solutions in the genesis and history of deposit formation. As a result of the impact on the lithosphere of mantle plumes rising along TCMFCFs, intense block deformations and tectonic movements are generated; rift systems, and volcanic–plutonic belts spatially combined with them, are formed; and intrusive bodies are introduced. These processes cause epithermal ore formation as a consequence of the impact of mantle plumes rising along TCMFCF to the lithosphere. At hydrocarbon fields, they play extremely important roles in conductive and convective heat, as well as in mass transfer to the area of hydrocarbon generation, determining the relationship between the processes of lithogenesis and tectogenesis, and activating the generation of hydrocarbons from oil and gas source rock. Detection of TCMFCFs was carried out using MMSS (the method of microseismic sounding) and MTSM (the magnetotelluric sounding method), in combination with other geological and geophysical data. Practical examples are provided for mineral deposits where subvertical transcrustal columns of increased permeability, traced to considerable depths, have been found; the nature of these unique structures is related to faults of pre-Paleozoic emplacement, which determined the fragmentation of the sub-crystalline structure of the Earth and later, while developing, inherited the conditions of volumetric fluid dynamics, where the residual forms of functioning of fluid-conducting thermohydrocolumns are granitoid batholiths and other magmatic bodies. Experimental modeling of deep processes allowed us to identify the quantum character of crystal structure interactions of minerals with “inert” gases under elevated thermobaric conditions. The roles of helium, nitrogen, and hydrogen in changing the physical properties of rocks, in accordance with their intrastructural diffusion, has been clarified; as a result of low-energy impact, stress fields are formed in the solid rock skeleton, the structures and textures of rocks are rearranged, and general porosity develops. As the pressure increases, energetic interactions intensify, leading to deformations, phase transitions, and the formation of chemical bonds under the conditions of an unstable geological environment, instability which grows with increasing gas saturation, pressure, and temperature. The processes of heat and mass transfer through TCMFCFs to the Earth’s surface occur in stages, accompanied by a release of energy that can manifest as explosions on the surface, in coal and ore mines, and during earthquakes and volcanic eruptions. Full article

CO₂ flooding technology has been established as a key technique that is both economically viable and environmentally sustainable, achieving enhanced oil recovery (EOR) while advancing CCUS objectives. This study addresses the challenge of optimizing CO₂ flooding well patterns in tight oil reservoirs through a geological–engineering integrated approach. A semi-analytical model incorporating startup pressure gradients and miscible/immiscible two-phase flow was developed to dynamically adjust injection intensity. An effective driving coefficient model considering reservoir heterogeneity and fracture orientation was proposed to determine well pattern boundaries. Field data from Blocks A and B were used to validate the models, with the results indicating optimal injection intensities of 0.39 t/d/m and 0.63 t/d/m, respectively. Numerical simulations confirmed that inverted five-spot patterns with well spacings of 240 m (Block A) and 260 m (Block B) achieved the highest incremental oil production (3621.6 t/well and 4213.1 t/well) while reducing the gas channeling risk by 35–47%. The proposed methodology provides a robust framework for enhancing recovery efficiency in low-permeability reservoirs under varying geological conditions. Full article

As the energy sector transitions toward decarbonisation, low-to-intermediate temperature geothermal resources in sedimentary basins—particularly repurposed oil and gas fields—have emerged as promising candidates for sustainable heat and power generation. Despite their widespread availability, the development of these systems is hindered by gaps in methodology, oversimplified modelling assumptions, and a lack of integrated analyses accounting for long-term reservoir and wellbore dynamics. This study presents a detailed, simulation-based framework to evaluate geothermal energy extraction from depleted petroleum reservoirs, with a focus on low-enthalpy resources (<150 °C). By examining coupling reservoir behaviour, wellbore heat loss, reinjection cooling, and surface energy conversion, the framework provides dynamic insights into system sustainability and net energy output. Through a series of parametric analyses—including production rate, doublet spacing, reservoir temperature, and field configuration—key performance indicators such as gross power, pumping requirements, and thermal breakthrough are quantified. The findings reveal that: (1) net energy output is maximised at optimal flow rate (~70 kg/s for a 90 °C reservoir), beyond which increased pumping offsets thermal gains; (2) doublet spacing has a non-linear impact on reinjection cooling, with larger distances reducing thermal interference and pumping energy; (3) reservoirs with higher temperatures (<120°C) offer significantly better thermodynamic and hydraulic performance, enabling pump-free or low-duty operations at higher flow rates; and (4) wellbore thermal losses and reinjection effects are critical in determining long-term viability, especially in low-permeability or shallow fields. This work demonstrates the importance of a coupled, site-specific modelling in assessing the geothermal viability of petroleum fields and provides a foundation for future techno-economic and sustainability assessments. The results inform optimal design strategies and highlight scenarios where the geothermal development of oil and gas fields can be both technically and energetically viable. Full article

The development of deep coalbed methane (CBM) wells faces challenges such as significant reservoir depth, low permeability, and severe liquid loading in the wellbore. Traditional drainage and gas recovery techniques struggle to meet the dynamic production demands. This study, using the deep CBM wells at the Jishen 15A platform as an example, proposes a “cyclic gas lift–wellhead compression-vent gas recovery” composite synergy technology. By selecting a critical liquid-carrying model, innovating equipment design, and dynamically regulating pressure, this approach enables efficient production from low-pressure, low-permeability gas wells. This research conducts a comparative analysis of different critical liquid-carrying velocity models and selects the Belfroid model, modified for well inclination angle effects, as the primary model to guide the matching of tubing production and annular gas injection parameters. A mobile vent gas rapid recovery unit was developed, utilizing a three-stage/two stage pressurization dual-process switching technology to achieve sealed vent gas recovery while optimizing pipeline frictional losses. By combining cyclic gas lift with wellhead compression, a dynamic wellbore pressure equilibrium system was established. Field tests show that after 140 days of implementation, the platform’s daily gas production increased to 11.32 × 10⁴ m³, representing a 35.8% rise. The average bottom-hole flow pressure decreased by 38%, liquid accumulation was reduced by 72%, and cumulative gas production increased by 370 × 10⁴ m³. This technology effectively addresses gas–liquid imbalance and liquid loading issues in the middle and late stages of deep CBM well production, providing a technical solution for the efficient development of low-permeability CBM reservoirs. Full article

The characteristics of marine–continental transitional shale reservoirs and the performance parameters of fracturing fluids, such as pH and mineralization, play a crucial role in influencing the flowback efficiency of these fluids. Excessive retention of fracturing fluids within the reservoir can lead to a significant decrease in permeability, thereby diminishing gas well productivity. This study investigates shale samples sourced from the marine–continental transitional shale formation in the eastern Ordos Basin, along with field-collected fracturing fluid samples, including formation water, sub-formation water, distilled water, inorganic acids, and organic acids, through flowback experiments. The results show that: (1) the flowback rate of shale fracturing fluids exhibits a positive correlation with salinity, with low-salinity fluids showing a dual effect on clay mineral hydration. These fluids increase the pore volume of the sample from 0.003 cm³/g to 0.0037 cm³/g but also potentially reduce permeability by 31.15% to 99.96%; (2) the dissolution effects of inorganic and organic acids in the fracturing fluids enhance the flowback rate by 16.42% to 22.25%, owing to their chemical interactions with mineral constituents; (3) in the development of shale gas reservoirs, it is imperative to carefully devise reservoir protection strategies that balance the fracture-inducing effects of clay mineral hydration and expansion, while mitigating water sensitivity damage. The application of acid preflush, primarily including inorganic or organic acids, in conjunction with the advanced fracturing techniques, can enhance the connectivity of shale pores and fractures, thereby improving fracture conductivity, increasing the flowback rate of fracturing fluids, and ensuring sustained and high gas production from wells. Full article