Carbon dioxide replacement represents a promising hydrate development strategy that effectively balances production efficiency and environmental considerations. However, its production efficiency is lower than that of the depressurization strategy. This limitation can be effectively alleviated by coupling carbon dioxide replacement with inhibitor injection. The design and optimization of the temperature–pressure operating window constrain its effective implementation. In the present work, the phase equilibrium conditions of carbon dioxide hydrate and methane hydrate were experimentally investigated. It was found that the experimental values obtained in this study are in excellent agreement with those calculated by the CSMHyd program. The average absolute relative deviations (AARD) for the experimental versus calculated results are 5.77% for methane hydrate and 2.66% for carbon dioxide hydrate. Then, the methodology for determining the recommended temperature–pressure combinations used in the carbon dioxide replacement strategy was proposed, and the size of region in which these combinations occur was quantified. The investigation results found that there are significant differences in the size of the recommended region for different sea areas, and inhibitor injection reduces the size of this recommended region. Injection of 3.0 wt% NaCl solution reduces the size of recommended region from 10.968 K·MPa to 8.366 K·MPa for pure methane hydrate, and a similar trend is also observed for natural gas hydrates. Based on the experimental results, the carbon sequestration potential of natural gas hydrate development using the carbon dioxide replacement strategy on core size was analyzed. The final simulation results show that 9.05 mol of carbon dioxide hydrate was obtained in the reaction vessel, which achieves effective CO2 sequestration. The investigation in this work provides theoretical support for dual goals of carbon sequestration and efficient gas production from gas hydrates.

Inter-well fracture communication is a persistent challenge in multi-well infill stimulation, often reducing production efficiency and compromising reservoir integrity. This study develops a mechanistic framework based on the Extended Finite Element Method (XFEM) with phantom node enrichment to simulate multi-fracture propagation between neighboring horizontal wells. The model couples poroelastic rock deformation, fracture-matrix fluid exchange, pressure-dependent leak-off, and fracture propagation governed by a traction-separation law, providing a fully integrated representation of hydraulic fracturing processes. Parametric analyses reveal that zero-stagger distance with simultaneous injection promotes complete fracture linking, while larger offsets or scheduled treatments mitigate communication through stress shadow effects. Increasing rock tensile strength enhances fracture repulsion and reduces tip-to-tip linking. Distinct pressure signatures differentiate linking fractures, which exhibit localized sagging, from non-linking fractures with monotonic gradients. The framework was validated against Displacement Discontinuity Method (DDM) benchmarks, Kristianovich-Geertsma-de Klerk (KGD) analytical solutions, and field-measured pressure data from the Daqing Oilfield, demonstrating strong goodness-of-fit and confirming model fidelity. This work finds useful application in designing perforation patterns, optimizing cluster spacing, and scheduling treatments in unconventional shale reservoirs. By enabling accurate prediction of fracture linking, coalescence, and repulsion, the framework provides practical guidance for maximizing stimulated reservoir volume while controlling unintended inter-well interference.

The creep response of composite salt rock depends on mineral composition, however, quantitative constitutive models that account for composition effects remain limited. In this paper, composition-controlled synthetic salt rock cores were prepared by high-temperature axial compaction using halite as the matrix and anhydrite or sylvite as accessory minerals. Anhydrite-halite specimens contained 0-80 wt.

Gas hydrate production can lead to reservoir strength degradation and an increase in effective stress, which may induce seabed subsidence and slope failure. This risk is particularly pronounced during multi-well production, where a larger area of the formation is affected, thereby increasing the likelihood of landslides. Considering the thermo–hydro–mechanical (THM) coupling characteristics inherent in gas hydrate exploitation, a slope stability evaluation model was developed by integrating these coupled processes with the finite element strength reduction method. The model was applied to investigate slope stability during multi-vertical well gas hydrate production. The results indicate that, under identical well spacing, a linear well layout parallel to the slope strike enhances slope stability compared with a layout perpendicular to the strike. For the same layout orientation, increasing both the well spacing and production pressure improves slope stability. Conversely, when using a vertical well network, slope stability decreases progressively with increasing well density for a given production duration. Slopes with excessively steep angles exhibit a high risk of failure, whereas reducing the slope angle progressively improves stability. These findings provide a theoretical basis for optimizing development plans for deepwater gas hydrate reservoirs.

As the global energy structure transitions toward low-carbonisation, ensuring the long-term sealing integrity of underground hydrogen storage has emerged as a critical challenge. In particular, the integrity of cement barriers in hydrogen environments is potentially threatened. This study systematically investigated the effects of hydrogen exposure on cement specimens through wave velocity, nuclear magnetic resonance (NMR), and uniaxial compression tests. These analyses revealed the physical properties and mechanical characteristics changes of cement specimens under hydrogen influence. The results indicate that hydrogen exposure slightly enhances the wave velocity of cement stones. Additionally, the total porosity of the specimens decreased due to a reduction in large pores, accompanied by a slight increase in small pores. Furthermore, the uniaxial compressive strength and Poisson's ratio of the cement specimens exhibited slight decreases, while the latter showed no substantial variation. This study elucidated the mechanical evolution patterns of hydrogen-cement interactions, thereby providing a crucial foundation for optimizing cementing materials and evaluating the integrity of hydrogen storage reservoirs.

Natural gas hydrate reservoirs are commonly hosted in fine-grained sediments, where creep-induced borehole shrinkage during production may cause pipe sticking and wellbore instability. For hydrate-bearing sediments in the northern South China Sea, the sediment skeleton was remolded using a quartz sand-kaolin mixture to reproduce the mineral composition and grain-size distribution of in-situ marine soils. Methane hydrate was synthesized by an in-situ formation method, and hydrate saturation was controlled by the excess-gas method. Triaxial creep tests were conducted to quantify the effects of deviator stress, hydrate saturation, and clay content on creep response. All specimens exhibited decelerating creep over 48 h; creep strain increased continuously while the strain rate gradually decreased. Increasing deviator stress from 3.95 to 8.88 MPa increased creep strain by a factor of 4.83 times, indicating that deviator stress dominates creep intensity. Increasing hydrate saturation from 0% to 60% increased creep strain by 7.19 times, and increasing clay content from 20% to 60% increased creep strain by approximately 3.69 times. Hydrate saturation and clay content mainly affected creep-rate magnitude without changing the decelerating pattern. In semi-logarithmic coordinates, creep strain exhibits an approximately linear relationship with lg(t). An empirical creep model incorporating these coupled effects was established and validated, with a maximum relative error below 5%.

Shale exhibits a semipermeable membrane effect, but it does not behave as an ideal semipermeable membrane. Membrane efficiency is a key parameter for characterizing the semipermeable membrane properties of shale and provides an important basis for wellbore stability analysis, showing significant engineering value. In this study, commonly used water-based and oil-based drilling fluids were selected. Shale samples wrapped with an artificial semipermeable membrane were immersed in these drilling fluids, and their mechanical properties were subsequently measured. Meanwhile, variations in water content were jointly measured using gravimetric measurements and nuclear magnetic resonance (NMR), and the relationships among drilling fluid type, rock strength, water content, and membrane efficiency were investigated. The results show that rock strength was highest after immersion in the oil-based drilling fluid, followed by the polyamine drilling fluid and the polyol drilling fluid. The attenuation law of rock strength induced by shale hydration damage was determined, and the relationship between rock strength and water content was established. A method for calculating the rock hydration damage coefficient based on the NMR T 2 signal was proposed, and its accuracy was experimentally verified. Furthermore, a rock strength-based method for characterizing shale membrane efficiency was established. This method enables membrane efficiency to be calculated using rock strength, drilling fluid activity, and formation water activity and can characterize the variation in membrane efficiency during wellbore stability analysis. Among the tested drilling fluids, the oil-based drilling fluid exhibited the highest membrane efficiency, approximately 0.71, followed by the polyamine drilling fluid, with a membrane efficiency of approximately 0.60. As the soaking time increased, the membrane efficiency continuously decreased.

Salt rock exhibits pronounced viscoelastic creep, continuously imposing radial extrusion loads on casing and threatening long-term well integrity. Field observations in the Missan Oilfield, Iraq, show that casing damage is concentrated near salt-non-salt interfaces, where lithologic contrasts intensify stress redistribution and mechanical coupling. This study integrates triaxial creep experiments, a calibrated modified Burgers model, UMAT implementation, and three-dimensional finite element simulations to investigate casing stress evolution and failure mechanisms. The calibrated model reproduces salt rock creep with a maximum relative strain error of 16.8%. Results show that post-cementing salt creep amplifies non-uniform radial loading at the interface, causing progressive casing stress concentration. At low inclination, the interface-casing intersection evolves into an elliptical annulus; the circumferential variation in equivalent wall thickness and stress-peak migration jointly weaken local stress concentration. However, when the inclination angle reaches approximately 45 degrees at beta = 0 degrees, the peak Mises stress begins to exceed that under the vertical-well condition. When alpha >= 65 degrees, the peak stress no longer decreases monotonically with azimuth but exhibits a decrease-increase trend. This indicates that eccentric loading and the additional bending moment dominate the transition from radial extrusion to coupled bending-shear-extrusion loading. A casing stress risk map and grade-selection chart are developed to support casing design in salt-interbedded formations.

Weakly cemented reservoir rocks can be treated as granular assemblies whose permeability is controlled by interparticle packing, rearrangement, and failure under different stress states. To clarify the seepage response of deep weakly cemented heavy-oil reservoir rocks, permeability tests were conducted on real core samples under triaxial shear and isotropic compression. The evolution of rock deformation and permeability was analyzed, and a stress-state-dependent permeability evolution model was established. The results show that, under shear, volumetric deformation can be divided into three stages: positive compression, negative compression, and net expansion. As confining pressure increases, volumetric compression increases and shear-induced dilatancy is suppressed. Diffuse dilatancy is more likely to occur under moderate confining pressure, whereas localized shear bands tend to develop under lower or higher confining pressures. During shearing, porosity and permeability are generally positively correlated but not fully synchronous, indicating that the establishment of effective seepage pathways lags behind the recovery of storage space during the transition from compaction to dilation. Under isotropic compression, pore structure evolution is relatively stable, permeability decreases continuously with increasing mean stress, and part of the permeability loss remains after unloading. These results demonstrate that permeability evolution is governed by fundamentally different particle rearrangement and pore-connectivity evolution mechanisms under different stress states. This study provides an experimental basis for evaluating flow conductivity, seepage-deformation coupling, and the design of dilatancy fracturing and volumetric stimu-lation parameters for deep weakly cemented heavy-oil reservoirs.

Gas hydrate resources have enormous potential, but their low permeability, weak cementation pose great challenges to economic and efficient development. To improve production efficiency, reservoir stimulation methods such as hydraulic fracturing are usually required to enhance flow conditions, and the effective implementation of these techniques relies on an in-depth understanding of fracture conductivity and its controlling factors. In this study, a flexible triaxial numerical model was first developed using a discrete-continuous coupling approach to calibrate the micromechanical contact parameters of hydrate-bearing sediments. Subsequently, a discrete element model incorporating proppant embedment was constructed to systematically investigate the effects of closure pressure, hydrate saturation, the ratio between proppant and formation median grain sizes (D50/d50), and proppant areal concentration on fracture closure, intrafracture porosity, volume of formation sand invasion, and fracture conductivity. The results show that increasing closure pressure significantly enhances fracture closure and reduces fracture porosity and conductivity; higher hydrate saturation strengthens hydrate-bearing sediments, constraining proppant embedment and formation deformation, thereby markedly enhancing fracture conductivity at low closure pressure, whereas the differences in conductivity among different saturations gradually diminish at high closure pressure. Increasing the proppant size ratio and areal concentration helps create a larger initial fracture width and porosity and maintain relatively high conductivity under high closure pressure, but at the cost of greater sand invasion volume and fracture closure. These findings provide useful guidance for proppant selection and fracture design optimization in hydraulic fracturing treatments of gas hydrate reservoirs.

Weakly cemented heavy-oil reservoir rocks are characterized by low cementation strength and loose particle contacts, making them prone to compaction and dilatancy during reservoir development. To reveal their shear evolution and acoustic emission (AE) response mechanisms, triaxial shear tests under different confining pressures were conducted on actual heavy-oil reservoir cores, with AE signals collected simultaneously. The results show that confining pressure significantly enhances the load-bearing capacity of the rocks. Under uniaxial conditions, the peak strength is approximately 2–8 MPa, whereas under a confining pressure of 15 MPa, the peak strength can approach 50 MPa. The volumetric deformation of the rocks generally exhibits compression followed by dilation. The AE response shows distinct early activation characteristics. Under medium to high confining pressures, the AE event rate, ring-down count rate, and energy rate mostly reach high levels before or near the dilatancy onset, whereas under low confining pressure, AE activity is mainly concentrated around the peak and post-peak stages. The peak frequency is generally lower than 200 kHz. Classification results based on peak frequency and the RA-AF criterion indicate that particle-activity-type, shear-type, and tensile-type AE all participate in the shear failure process, with particle-activity-type AE accounting for approximately 40% on average. The dilatancy and failure of weakly cemented heavy-oil reservoir rocks result from the combined effects of particle skeleton compaction, cementation failure, frictional sliding, microcrack propagation, and local shear band formation. This study provides experimental evidence for damage identification, development evaluation, and improvement of AE interpretation methods for weakly cemented heavy-oil reservoir rocks.

Gas hydrate is anticipated to serve as a viable substitute for traditional fossil fuels in the near future. Unfortunately, some geomechanical issues may arise during its development, threatening its efficient development and the marine ecology. It is regrettable that research in this area remains inadequate. In the present work, a coupled mathematical model was used to analyze sediment stability during the prolonged extraction of natural gas from hydrate-bearing sediments. Moreover, the applicability of this model was verified by comparison. Based on this, the factors influencing sediment stability were then explored, and the corresponding mechanisms were thoroughly discussed. The comparison results showed that the results obtained by the mathematical model used were more accurate, as it included more physical fields and factors. Therefore, it was more suitable for numerical simulation of sediment stability during the long-term development of gas hydrates. Moreover, it was demonstrated that the strength weakening caused by hydrate dissociation and the stress change due to depressurization were two main mechanisms for sediment deformation or instability. Although gas production increased with increasing depressurization amplitude, permeability and hydrate saturation, as well as shallower reservoir depth, the sediment stability deteriorated accordingly. Interestingly, both sediment stability and gas production were unaffected by the heating amplitude during the prolonged development operation. This study offers a fresh perspective on mitigating the risk of sediment instability while ensuring the efficient development of marine hydrates.

During deep unconventional resource extraction, high temperatures and dynamic loads exert a substantial impact on the stability of geotechnical structures. In this study, an improved Split Hopkinson Pressure Bar (SHPB) system was employed to conduct dynamic impact tests on high-temperature-treated red sandstone specimens at different impact velocities. A systematic analysis was carried out to investigate the effects of high temperature and impact velocity on the changes in dynamic mechanical properties and failure modes of the sandstone. Based on sieve test results, the size distribution of fragmented particles was quantified using fractal dimension analysis. Furthermore, by integrating thermal gravimetric analysis (TGA) and scanning electron microscopy (SEM), a clear correlation between the thermal damage evolution of sandstone and its microstructural degradation was established, thus providing novel insight into the dynamic failure mechanism. The results indicate that the dynamic mechanical properties of red sandstone show a significant temperature-dependent effect, following a decreasing trend described by a quadratic function. An increase in temperature significantly decreases the difference in dynamic strength of rocks under varying impact velocities. The particle size distribution of sandstone fragments displays statistical self-similarity, remaining unaffected by changes in temperature or loading velocity. At high loading rates, strain rate effects lead to a reduced influence of temperature on the fractal dimension. These findings offer valuable insights for the optimization of wellbore stability and enhancement of rock fragmentation efficiency.

The Shenhu sea area is rich in unconsolidated hydrate reserves, but the formation mineral particles are small, the rock cementation is weak, and the coupling mechanism of hydrate phase change, fluid seepage, and formation deformation is complex, resulting in unclear productivity change law under depressurization exploitation. Therefore, a thermal–fluid–solid–chemical coupling model for natural gas hydrate depressurization exploitation in the Shenhu sea area was constructed to analyze the variation law of reservoir parameters and productivity. The results show that within 0–30 days, rapid near-well pressure drop (13.83→9.8 MPa, 36.37%) drives peak gas production (25,000 m3/d) via hydrate dissociation, with porosity (0.41→0.52) and permeability (75→100 mD) increasing. Within 30–60 days, slower pressure decline (9.8→8.6 MPa, 12.24%) and fines migration cause permeability fluctuations (120→90 mD), reducing gas production to 20,000 m3/d. Within 60–120 days, pressure stabilizes (~7.6 MPa) with residual hydrate saturation < 0.1, leading to stable low permeability (60 mD) and gas production (15,000 m3/d), with cumulative production reaching 2.2 × 106 m3. This study clarifies that productivity is governed by coupled “pressure-driven dissociation–heat limitation–fines migration” mechanisms, providing key insights for optimizing depressurization strategies (e.g., timed heat supplementation, anti-clogging measures) to enhance commercial viability of unconsolidated hydrate reservoirs.

Studying how natural fracture networks (NFNs) interact with hydraulic fractures is of great significance for the exploitation of unconventional reservoirs with well-developed NFNs. The arrangement and combination of unit modules are used to simulate NFNs. The parameters of the natural fracture network are adjusted by varying the inclination angle between small rock block units, network density, and cementation strength. True triaxial fracturing laboratory experiments were performed to investigate the influence of NFNs on hydraulic fracture propagation under different conditions during horizontal well hydraulic fracturing, including natural fracture network (NFN) inclination angle, density, cementation strength, and horizontal stress difference. The study found that the smaller the angle between the natural fracture and the maximum horizontal principal stress, hydraulic fractures tend to propagate along the NFN. Conversely, they are more likely to cross the NFN. As the density of the NFN increases, the hydraulic fracture network gradually transforms into a complex fracture network dominated by natural fractures. Higher NFN density enhances fracture area and complexity. Lower cementation strength facilitates NFN activation, and the more likely branch fractures are to form. Conversely, a single planar fracture is more likely. Lower horizontal stress differences reduce in-situ stress control over fracture propagation, and the more likely the hydraulic fracture is to extend along natural fractures. Conversely, the more likely the hydraulic fracture is to directly cross natural fractures, resulting in lower fracture complexity. Fracture propagation direction analysis confirmed that the modified R P criterion better matches field conditions and can satisfy the applicability of intersection criteria under more complex circumstances. This study offers practical insights for fracturing well-developed NFN reservoirs.

The Shenhu sea area is characterized by substantial natural gas hydrate (NGH) resources, where clay minerals exert a considerable influence on the mechanical properties of the surrounding sediments. This influence is further amplified during hydrate decomposition. Given this context, the composition and geological characteristics of the shallow, clay-rich, hydrate-bearing sediments specific to the Shenhu sea area was investigated. Subsequently, a series of carefully controlled triaxial mechanical experiments were performed on in-situ synthesized hydrate-bearing sediments, which determined the variations in strength parameters under different clay contents, and facilitated the development of an effective strength criterion through multiple regression analysis. The results indicate that: (1) Clay minerals significantly affect the mechanical behavior of hydrate-bearing sediments. An increase in clay content is associated with a decrease in peak strength. Under the influence of hydrate saturation and effective confining pressure, hydrate-bearing sediments exhibit similar mechanical responses across varying clay contents. The peak strength demonstrates a linear relationship with hydrate saturation while a non-linear relationship with effective confining pressure. (2) Cohesion and the internal friction angle generally decrease with increasing clay content and decreasing hydrate saturation. However, variations in cohesion are more pronounced and follow a more consistent pattern, which are characterized as a function of clay content and hydrate saturation. (3) Based on the Mohr-Coulomb criterion, a high-precision strength criterion for unconsolidated hydrate-bearing sediments is established incorporating the effects of clay content, hydrate saturation, and effective confining pressure. This research provides a valuable reference for the design and optimization of NGH drilling and production operations in the Shenhu sea area.

Addressing steam channeling and water invasion in multi-cycle thermal recovery is now a critical challenge in heavy oil development. The study developed a high-temperature plugging system based on dual-crystal synergistic effects. The plugging agent, composed of calcium chloride, sodium sulfate, sodium carbonate, polymers, and dispersants, precipitates CaSO4 and CaCO3 crystals upon injection into the formation, synergistically sealing high-permeability channels. Experiments demonstrated that the agent effectively crystallizes within a temperature range of 60–200 °C. Displacement tests revealed well plugging performance under high-temperature conditions, with a core plugging rate of 99.3

The shallow hydrate reservoir in the Shenhu Sea area is mainly composed of clayey silt. Clay mineral has an important impact on the mechanical properties, and the hydrate decomposition aggravates this impact. Therefore, the composition and geological conditions of shallow clay hydrate-bearing sediment in Shenhu sea area are fully considered, hydrate-bearing sediment samples with similar physical properties are synthesized in situ. Then, indoor triaxial mechanical experiments are carried out, and the effect of clay minerals on the mechanical property is analyzed. The results show that the clay content and clay type have an important impact on the mechanical properties of unconsolidated hydrate-bearing sediment. With the increase of clay content, the strain hardening characteristics are prominent, the yield stage is longer, and the plasticity is enhanced. Hydrate-bearing sediment with different clay content shows similar mechanical laws under the influence of hydrate saturation and effective confining pressure. The peak strength, elastic modulus and Poisson’s ratio all show a downward trend, but the peak strength and elastic modulus change more obviously. The peak strength changes linearly with hydrate saturation, while nonlinearly with effective confining pressure, especially 0–3 MPa. This is the comprehesive result of clay particle’s movement and fragmentation, clay hydration and expansion, affecting hydrate formation and sediment cementation. When the content ratio of montmorillonite/illite decreases, the peak strength and elastic modulus show an increasing trend. Because the frictional resistance and connection strength of illite crystal layer are larger with bigger particle size, weaker hydration and thinner water film. The research can provide reference for drilling and production engineering of natural gas hydrate (NGH) reservoir in the Shenhu sea area.