Search Results (216)

The thermal history of carbonate successions is fundamental to constraining hydrocarbon generation and reservoir diagenesis, yet traditional proxies such as vitrinite reflectance and apatite fission-track analysis are often inapplicable to marine carbonates because organic matter and suitable heavy minerals are scarce. This study evaluates an integrated carbonate isotope (Δ₄₇) thermometry and in situ U-Pb geochronology approach using a micrite matrix and three dolomite-bearing samples from the Upper Permian Changxing Formation in the Yuanba area, northern Sichuan Basin, southwestern China. The measured apparent clumped isotope temperatures (TΔ₄₇) range from 127.8 to 174.6 °C. The micrite matrix yields a U-Pb age of 257 ± 1.2 Ma, consistent with an early depositional or syndepositional origin, whereas the dolomite samples yield younger diagenetic ages. Coupling these time–temperature constraints with an exchange–diffusion model for solid-state reordering provides a preliminary, well-scale thermal scenario for the sampled intervals. The preferred model suggests rapid heating during Late Permian–Early Triassic and Middle Jurassic burial, followed by peak heating to approximately 220 °C in the Late Cretaceous at modeled maximum burial depths exceeding 8000 m, and subsequent cooling during Yanshan–Himalayan uplift and denudation. A conditional maturity model predicts that the underlying Wujiaping Formation source rocks entered the main gas-generation window (1.3% < Ro < 2.6%) by the Middle Jurassic and became overmature during peak heating in the Late Cretaceous. This dual-proxy framework is promising for carbonate-dominated petroleum systems but requires validation with a larger sample set and independent thermal indicators. Full article

For casing damage phenomena including casing corrosion, rupture, and seal failure that frequently occur in carbon capture, utilization, and storage (CCUS) injection-production wells under long-term gas injection and pressure fluctuations, combined with the characteristics of ultra-fine cement slurry such as concentrated hydration heat release and vulnerability to acidic environment corrosion, this study synthesized tartaric acid-intercalated Mg-Al layered double hydroxides (TA-LDHs) through ion-exchange reaction as a functional retarder, and focused on screening the water–cement ratio as well as the dosages of fluid loss additive and dispersant suitable for CCUS working conditions. The results demonstrate that at a water–cement ratio of 0.7 with 1.5% fluid loss additive TSJ-1, 0.4% dispersant FSJ-1, and 0.2% TA-LDHs retarder, the cement slurry presents excellent rheological properties, a short thickening transition time, and remarkable resistance to acidic environment erosion. Plugging performance evaluations reveal that under simulated formation water conditions, the system maintains a breakthrough pressure gradient above 90.5 MPa·m⁻¹ and a plugging efficiency of more than 99%, and after 30 days of curing, its compressive strength reaches 29 MPa while the plugging efficiency is improved to 99.37%. Furthermore, after exposure to CO₂-saturated simulated formation brine at 80 °C and 20 MPa for 30 days, the TA-LDHs-modified cement exhibited a compressive strength of 27.0 MPa and a strength retention of 93.1%, while its permeability increased by only 23.1%. In comparison, the compressive strength retention of the control cement was 80.8%, and its permeability increased by 138.5%. These results indicate that the TA-LDHs-modified ultra-fine cement possesses favorable plugging performance and improved resistance to CO₂-induced degradation, showing potential for casing damage remediation in CCUS wells. Full article

During shale gas fracturing operations, large volumes of low-temperature fracturing fluid carrying proppant are injected into the high-temperature wellbore, resulting in intense transient heat exchange between the fracturing fluid, the wellbore structure and the surrounding formation. To predict the wellbore temperature field during fracturing, this paper treats proppant-laden slurry as a homogeneous fluid and considers the effects of temperature and proppant concentration on the fluid’s equivalent thermal properties. Based on the energy conservation equation, a transient wellbore heat-transfer model was developed by coupling axial convective heat transfer within the casing, radial heat transfer through the multi-layer wellbore media, and transient thermal conduction in the formation. The radial heat-transfer process was solved using the equivalent thermal resistance method, and the model was validated through finite element simulation. The computational results indicate that under base operating conditions—with an injection temperature of 20 °C, an injection flow rate of 12 m³/min, and an injection duration of 90 min—the bottomhole temperature rapidly drops to the 20–25 °C range, subsequently entering a low-temperature quasi-steady-state phase; following pump shutdown, the bottomhole temperature gradually recovers, reaching approximately 40 °C 120 min after shutdown. The computational results of this theoretical model regarding the variation pattern of the bottomhole temperature, the vertical temperature distribution, and the radial temperature response show good agreement with the finite element simulation results. Parameter analysis indicates that increasing the injection rate from 8 to 16 m³/min shortens the cooling time to below 25 °C from approximately 13–14 min to 8–9 min, while the stable bottomhole temperature only decreases slightly from 23.0 to 21.3 °C. Increasing proppant concentration from 6% to 15% has a weak influence on temperature evolution. In contrast, injection temperature is the dominant factor: when the injection temperature is 5, 15, and 30 °C, the stable bottomhole temperatures are approximately 8, 17, and 31 °C, respectively. The sensitivity analysis indicates that injection temperature is the dominant factor affecting the wellbore temperature field, followed by injection rate, while proppant concentration is only weakly sensitive. The results provide theoretical support for wellbore temperature prediction and fracturing parameter optimization. Full article

Short drilling distances in soft coal seams prone to gas outbursts are mainly caused by drillpipe jamming from the accumulation of drill slag. This poses a gas hazard and limits gas utilization. A novel borehole-protection and pressure-relief (BPPR) drillpipe with three channels is proposed to solve this problem. However, the structural principle of the BPPR drillpipe differs significantly from that of conventional drillpipes, and the migration mechanisms of drill slag and airflow inside the borehole remain unclear. In this paper, the migration behavior of drill slag and its influencing factors during BPPR drillpipe drilling were investigated based on mechanical analysis and CFD-DEM coupling simulations. The results show that when air velocity exceeds the minimum suspension velocity of slag, the slag entering through sieveholes can be smoothly discharged by airflow. Small vortices form at the sieveholes but do not block slag discharge. The key factors affecting slag discharge are air velocity, slag volume, and particle size. Higher air velocity increases the slag transport speed and discharge rate. A larger slag volume reduces the average transport speed at the same air velocity. Larger particles need greater air velocity, or they settle at the bottom. Drillpipe rotation speed has little effect on slag transport. To ensure effective slag discharging, air pressure and velocity should be increased. In addition, the sieveholes on the BPPR drillpipe surface can regulate the slag volume and particle size entering the inner discharge channel. This matches the slag load with the airflow capacity and prevents blockages in the inner discharge channel. Full article

This study addresses the significant increase in gas content and gas pressure caused by the rising proportion of high gas, low-permeability coal seams under high geostress conditions. This problem not only limits the efficient extraction of coalbed methane (CBM) but also poses a serious threat to mining safety. To overcome this challenge, a novel water-based ultrasonic cavitation-enhanced coalbed methane recovery (WUC-ECBM) is proposed. A self-developed multimodal ultrasonic cavitation reaction system is used to treat coal samples at different cavitation power levels (0–1100 W). Mechanical tests are then performed, and the damage evolution process is synchronously characterised using a multichannel acoustic emission monitoring system. Permeability tests are also conducted to evaluate the effect of ultrasonic cavitation on coal seepage performance. The results show that ultrasonic cavitation systematically alters the mechanical behaviour of coal, driving the evolution from microstructural modification to macroscopic mechanical response. The compressive strength decreased by up to 53.71%, and the elastic modulus fell to 1.34 GPa, indicating a marked reduction in coal stiffness. The cumulative acoustic emission energy decreased to 0.77 × 10⁶ mV·ms, demonstrating that ultrasonic cavitation promoted the initiation, propagation, and coalescence of internal microcracks, thereby accelerating damage evolution from microscale to macroscale. A progressive failure mechanism, characterised by primary cavitation-induced damage followed by secondary loading-induced damage, is ultimately formed. In addition, ultrasonic cavitation significantly enhanced coal permeability, with a maximum increase of 504.22%. These findings provide a theoretical basis for the further development of WUC-ECBM and for the efficient extraction of CBM. Full article

Retained water associated with water-locking can restrict gas production in heterogeneous tight sandstones, and the activity and phase stability of many surfactant treatments are reduced under high-temperature, high-salinity (HTHS) conditions. In this study, a composite surfactant formulation, CSF-1, designed to lower gas–brine capillary resistance and adjust sandstone wettability under representative reservoir constraints, is reported. Its performance was evaluated using thermal aging, surface tension and contact angle measurements, geochemical compatibility tests, laser diffraction, SEM/EDS, and core flooding combined with stagewise low-field nuclear magnetic resonance (LF-NMR). CSF-1 remained macroscopically homogeneous after aging at 170 °C in 188.314 g/L hypersaline brine and retained low gas–brine surface tension when measured at 25 °C after aging. In core flooding tests, CSF-1 increased the apparent gas permeability from 0.203 to 0.388 mD relative to the SFW-saturated water-locked state, corresponding to a 91.1% improvement. One- and two-dimensional NMR measurements provided comparative relaxation domain evidence that CSF-1 promoted the removal and redistribution of relatively mobile and weakly restricted fluid signals and reduced residual signal clustering. The shortest T₂ relaxation domains were less affected. The absence of replicate core flooding and associated LF-NMR runs, together with the non-equivalent Ref-S comparison, precludes a statistically rigorous cross-agent performance ranking. These results support the laboratory water-locking mitigation potential under the tested conditions, without implying calibrated pore-size-resolved removal or field-scale confirmation. Full article

Wellbore fluid flow and heat transfer are strongly coupled during drilling and well construction, where temperature, pressure, rheology, gas behavior, transient operations, and cementing displacement jointly affect pressure-window control and wellbore safety. This review synthesizes advances in coupled wellbore thermal–hydraulic numerical simulation, emphasizing governing equations, discretization strategies, coupling algorithms, rheology and turbulence closures, verification and validation, computational efficiency, uncertainty quantification, and AI-assisted deployment. A bibliometric-guided critical review was conducted using an 841-record Web of Science corpus, 79 screened technical records, 86 screened OnePetro field-facing records, and representative prior reviews. CiteSpace was used to identify knowledge structure and thematic evolution, while screened records were coded by governing physics, numerical method, closure assumption, model output, validation evidence, and deployment relevance. The literature is organized into five model families: wellbore temperature and heat transfer; annular non-Newtonian flow, rheology, turbulence, and CFD; pressure-window and transient hydraulics; cementing displacement and well-construction flow; and AI-assisted calibration and deployment. The synthesis shows that field-deployable simulation requires consistent state variables, transparent closure hierarchies, benchmark validation, uncertainty reporting, CFD-to-well-scale transfer, reduced-order implementation, and physics-constrained AI updating. Full article

To address the complex pressure-response mechanisms and difficulties in quantitatively characterizing dynamic reservoir properties during CO₂ geological storage in tight oil reservoirs, this work develops a dual-region composite seepage model coupling reservoir heterogeneity and CO₂-induced fluid property variation. The reservoir is divided into a near-well CO₂-stimulated zone and a far-field unstimulated zone. Combining the Laplace transform and the Stehfest368 numerical inversion method, we derive the analytical solutions of the bottom-hole pressure (BHP) and its derivative, and we establish a complete transient BHP monitoring and parameter inversion framework. The pressure-derivative curves are divided into five typical flow stages: wellbore storage, skin transition, inner-region radial flow, inter-region transition and outer-region radial flow. The key parameters, including wellbore storage coefficient, skin factor, mobility ratio, storativity ratio and CO₂ swept radius, can be accurately inverted via the BHP data analysis, which quantitatively characterizes flow capacity evolution, stimulated region scale and fluid flow patterns after CO₂ injection. The field application on two production wells in H138 block verifies the reliability of the proposed method. Further numerical simulation validation, measurement error sensitivity analysis and cross-verification of reservoir parameters are supplemented to prove the robustness and the applicability of the model. This study provides solid theoretical and technical support for on-site pressure monitoring, storage performance evaluation and operation optimization of CO₂ geological storage in tight reservoirs, and it also offers a reference for long-term storage security and storage capacity assessment. Full article

Mobile pipeline refers to a type of pipeline that can be laid and recovered at any time as required, mainly used for product oil transportation. After the completion of the transportation mission, the oil remaining inside the pipeline needs to be evacuated before recovering. Water-driven oil evacuation is commonly used for this purpose. In this paper, the water-driven oil evacuation in an inclined inverted U-shaped pipe was investigated. A numerical model coupling the VOF interface-capturing method, the CSF surface-tension model, and the SST k–ω turbulence model was established and validated against visualization experiments. The oil–water two-phase displacement characteristics in this special pipe configuration were systematically analyzed. The results show that a critical inlet superficial water velocity exists during the evacuation process. Complete oil evacuation can be achieved only when the inlet superficial water velocity exceeds this critical value. The critical velocity increases with increasing pipe inclination angle and pipe diameter. When the inlet superficial water velocity is lower than the critical value, vortical structures and backflow are readily generated at the oil front and within the oil phase, leading to oil accumulation near the end of the upper horizontal section and the formation of a stable retained oil layer in the downward-inclined section. Moreover, larger inclination angles and pipe diameters intensify oil retention and reduce the evacuation efficiency under subcritical conditions. All conclusions are drawn based on the No. 0 diesel–water system at 25 °C, and the applicable scope is limited to working conditions with similar fluid physical properties. Full article

Hydraulic fracturing is a key stimulation technique for enhancing the permeability of tight sandstone-hosted uranium deposits. However, existing hydraulic fracture network evaluation methods are primarily applicable to stress regimes in which the vertical principal stress exceeds the horizontal principal stress, making them unsuitable for evaluating low-angle or subhorizontal hydraulic fractures formed under high-horizontal-stress and low-vertical-stress conditions. To address this limitation, this study develops a semi-quantitative method for evaluating hydraulic fracturing effectiveness under stress regimes characterized by high horizontal stress and low vertical stress. The proposed method introduces a Stoneley-wave attenuation index and combines it with Stoneley-wave chevron-apex responses to identify hydraulically fractured intervals. By further integrating conventional well-log data to reduce interference from borehole enlargement, lithological boundaries, and natural fractures, the method supports the identification of hydraulically induced fractures and provides a semi-quantitative assessment of their development. The method was applied to a hydraulic fracturing pilot test for in situ leaching uranium mining in the Bayingobi Basin, Alxa, China, where it supported the identification of hydraulically induced fractures and fractured intervals in both stimulation and monitoring wells. Field application results support the engineering applicability of the proposed method and provide preliminary validation of its effectiveness. The results indicate that this method provides an effective logging-based approach for evaluating hydraulic fracturing performance and investigating fracture propagation in tight sandstone-hosted uranium deposits. Full article

This study investigates how O₂ concentration affects the combustion performance and kinetic response of Changji and Fushun oil shales under CO₂-based oxy-fuel atmospheres. Coupled TGA–DSC–MS analysis was performed to characterize thermal decomposition, heat release and absorption, gaseous product evolution, and apparent kinetic parameters. The results show that raising the O₂ concentration facilitates oil shale combustion. The TG–DTG and heat flow profiles move to lower-temperature regions as O₂ concentration increases. At 20 °C·min⁻¹, increasing the O₂ concentration from 35% to 100% reduced T_p1 and T_p2 from 357.3 and 519.7 °C to 331.2 and 491.5 °C for CJ oil shale, and from 352.3 and 484.0 °C to 326.6 and 429.7 °C for FS oil shale, respectively. These shifts were accompanied by decreases in ignition and burnout temperatures and an increase in the comprehensive combustion index. Fushun oil shale shows a more concentrated main mass-loss and heat-release region than Changji oil shale. It also exhibits lower ignition and burnout temperatures, indicating stronger overall combustion reactivity. By contrast, Changji oil shale displays more evident mass loss and thermal responses at high temperatures, suggesting a greater contribution from carbonate mineral decomposition in the later reaction stage. MS results further show that CO₂, H₂O, SO₂, and NO₂ release mainly occurs within 300–600 °C. Their release peaks shift toward lower temperatures as the O₂ concentration increases, indicating that oxygen-enriched atmospheres promote the oxidative conversion of organic carbon, hydrogen-containing structures, and S- and N-containing functional groups. The Vyazovkin nonlinear iso-conversional analysis provides conversion-dependent apparent activation energies rather than a single global kinetic parameter. The substantial variation in E_α with conversion highlights the overlapping and multi-stage nature of oil shale combustion. When the O₂ concentration is raised from 21% to 75%, E_α generally follows an upward trend; under pure O₂, however, it drops sharply. This non-monotonic variation suggests that O₂ concentration changes not only the combustion rate but also the dominant reaction routes at different conversion stages. These findings provide experimental support for selecting suitable oxy-fuel combustion conditions and improving the clean and efficient utilization of oil shale. Full article

Water influx calculations in high-permeability sandstone gas reservoirs often overlook the contributions of dissolved gas evolution and residual gas expansion within the aquifer. To address this limitation, a novel material-balance-based water influx model is developed for confined gas reservoirs. The model comprehensively integrates six physical mechanisms: gas-zone pore volume contraction, irreducible water expansion, aquifer water expansion, aquifer pore contraction, residual gas expansion, and dissolved gas evolution. A dimensionless water influx intensity type-curve and an analytical expression for component-wise water influx are derived, enabling quantitative decomposition of the contribution from each driving mechanism. The proposed method is applied to 11 production wells in the W Gas Field. Water influx is identified using three approaches—production performance analysis, the apparent reservoir pressure method, and the multi-factor type-curve method—and the calculated water influx volumes are systematically compared. Results show that the production performance method can only detect wells with a strong water influx response. The apparent reservoir pressure method yields physically unreasonable negative water influx values in confined gas reservoirs, indicating limited applicability. In contrast, the proposed model agrees well with the type-curve method, with relative errors below 10%. Component-wise calculations reveal that during early development, aquifer water expansion and aquifer pore contraction together account for over 60% of the total water influx, dominating the process. As reservoir pressure declines continuously, the contribution of dissolved gas evolution increases substantially, exceeding 30% in the middle-to-late development stage and becoming a non-negligible factor. Based on the component-wise water influx results, aquifer drive energy and activity are evaluated using the water-drive index and the water influx constant. Gas Group IV and the Lower Gas Group I exhibit “strong water drive + active” characteristics. Furthermore, gas–water contact rise height and advancement distance are calculated using both the volumetric method and a pore volume iteration method that accounts for actual structural geometry. The volumetric method systematically overestimates results by 15–30%, whereas the structural geometry-based method provides higher accuracy. According to the rise magnitude, the study area is classified into high-, moderate-, and low-risk water breakthrough zones. Wells A3H and A8 in Gas Group IV exhibit the highest risk, with rise magnitudes of 30.19% and 37.75%, respectively. This study provides a theoretical foundation and technical support for water influx performance prediction and differentiated water-control development in analogous high-permeability sandstone gas reservoirs. Full article

Fracturing is the dominant stimulation technique for low-porosity, low-permeability dolomite gas reservoirs, yet the lack of systematic laboratory research on multistage alternating acid etching mechanisms restricts field construction parameter optimization. Targeting the low-permeability Xixiangchi Formation dolomite reservoir in the eastern Sichuan Basin, this work develops a high-temperature, high-pressure core acid etching system coupled with 3D surface scanning. A reliable lab-to-field parameter conversion is established based on the Reynolds and Froude similarity criteria. Four-factor three-level orthogonal tests are conducted to quantify the impacts of pad fluid-to-acid viscosity ratio, total acid volume, pumping rate, and alternating injection stages on JRC-characterized wall roughness and fracture conductivity. The results show an identical factor dominance ranking for both indicators: viscosity ratio > pumping rate > injection stages > total acid volume. The optimal stimulation scheme is determined as a 50:1 viscosity ratio, 120 mL total acid volume, 12.54 mL/min laboratory pumping rate (equivalent to 8 m³/min in field operations), and 3 alternating injection stages. An elevated viscosity ratio intensifies viscous fingering, induces heterogeneous dolomite dissolution, and forms abundant irregular asperities on fracture surfaces. These self-supporting rough structures sustain stable seepage channels and markedly improve conductivity, verifying the positive roughness-conductivity correlation and revealing the core mechanism of heterogeneous etching-driven conductivity enhancement. The findings provide direct experimental support and parameter guidance for multistage alternating acid fracturing design in the Xixiangchi Formation and analogous tight dolomite reservoirs. Full article

The Hexi Corridor Basin Group, renowned for its Carboniferous source rocks, has emerged as a pivotal target for oil and gas exploration. This study integrates fieldwork, drilling, and geochemical data to analyze the Carboniferous lithofacies and paleogeography of the basin group, which is marked by extensive transgressive deposits. The Hexi Corridor experienced three key evolutionary phases during the Carboniferous. During the Early Carboniferous (deposition stage of the Qianheishan and Chouniugou Formations), crustal subsidence formed the Qilian epicontinental sea. Marine water intruded from the southeastern Qinling Mountains, and clastic sediments were supplied by the Alashan and Ordos oldlands to the north, developing lagoon-tidal flat facies interbedded with coal seams. As marine transgression expanded during the deposition of the Chouniugou Formation, the marine domain of the South Qilian area connected with the Beishan Trough, resulting in sedimentary differentiation between barrier-lagoon and open-coast deposits within this region. In the Late Carboniferous (deposition stage of the Jingyuan to Taiyuan Formations), transgression peaked; the marine area extended northward to Jiayuguan and eastward to connect with the North China Sea. Sediment thickness in the Helan Aulacogen changed sharply due to fault movement. This area was dominated by littoral-neritic tidal flat deposits with extensively developed coal seams, and detrital materials were still sourced from the Dunhuang–Alashan and Longxi oldlands. The entire evolutionary process was marked by tectonic control on basin development, multi-directional marine transgression, and persistent terrigenous sediment supply. Full article

This study addresses the poorly understood fracture propagation mechanisms in continental shale oil reservoirs with multi-lithologic combinations, specifically those in the lower third member of the Shahejie Formation, Bonan Sag, which exhibit complex lithology, coexistence of bedding planes and natural fractures, and pronounced mechanical anisotropy. We conduct small scale true triaxial hydraulic fracturing physical simulation experiments using limestone mudstone, felsic–lime mixed shale, and their combined rock samples. We innovatively introduce the hydraulic fracture complexity coefficient (F_h), the bedding plane fracture complexity coefficient (F_l), and the comprehensive fracture complexity coefficient (F_T) to enable quantitative evaluation of fracture complexity. The results show that high-viscosity fracturing fluid promotes vertical propagation and improves proppant placement, but yields relatively simple fracture geometry. Low-viscosity fracturing fluid readily activates bedding plane fractures, yet limits fracture height; a combined viscosity strategy can synergistically optimize the overall fracturing performance. The “high–low–high” viscosity sequence achieves the highest comprehensive fracture complexity coefficient (F_T), simultaneously providing large fracture height, high complexity, and effective proppant transport. Although increasing the injection rate significantly reduces the breakdown pressure and increases fracture width, it contributes marginally to vertical fracture growth. For fracturing multi-lithologic shale oil reservoirs, the recommended technical strategy is a “high-low-high” viscosity sequence combined with a moderately increased injection rate” to maximize the stimulated reservoir volume and overall fracturing effectiveness. Full article