Gas Technology Institute

This cross-sectional study assessed the impact of four abdominal exercises (crunch, abdominal drawing-in maneuver [ADIM], pelvic floor muscle contraction, and de Gasquet basic exercise) on inter-recti distance (IRD) and linea alba (LA) distortion and thickness in parous women. Parous women underwent ultrasound assessment during four abdominal exercises. The primary outcome was IRD at supra- and infraumbilical levels. Secondary outcomes were LA distortion and thickness. Transversus abdominis (TrA) activation was assessed simultaneously. Exercises were compared using linear mixed-effects models and Tukey-adjusted pairwise tests. Fifty-four parous women participated. Supraumbilically, the crunch showed the greatest IRD decrease (EMM +2.48mm), but this was not significantly different from ADIM, pelvic floor muscle contraction, or de Gasquet exercise (Tukey p≥0.07). The crunch was associated with increased LA distortion during the exercise compared with other exercises (supra: +0.26±0.05; infra: + 0.35±0.07 distortion units; both p<0.001), while the other three exercises reduced or maintained distortion during the exercise. Supraumbilical LA thickness increased during crunch compared with the other exercises (Tukey p≤0.05). TrA effects were exercise-specific: greater TrA thickening was associated with greater IRD decrease during ADIM, whereas lower TrA thickening was associated with greater IRD decrease during crunch. The crunch showed the largest supraumbilical immediate reduction in IRD but was accompanied by increased LA distortion. In contrast, the other three exercises were associated with smaller IRD changes and lower distortion. Lower TrA activation during crunch was associated with increased LA deformation, and apparent medial convergence of the rectus abdominis during the exercise. This research was registered on ClinicalTrials (NCT04501302).

ABSTRACT This study presents a comprehensive characterization of the low‐efficiency reservoirs within the Chang 6 member of the Ordos Basin, elucidating their formation mechanisms and establishing quantitative identification standards. These reservoirs typically develop in low‐energy sedimentary microfacies, specifically the margins of underwater distributary channels and inter‐distributary bays. Petrological analysis reveals that the reservoirs consist of fine‐grained feldspar sandstones rich in plastic interstitial materials and carbonate cements (&gt;5%), exhibiting ultralow physical properties (average porosity 7.12%, average permeability 0.27 mD) and a restricted pore structure (average displacement pressure 1.79 MPa, median throat radius 0.03 µm). The genesis of these low‐efficiency zones is governed by a sedimentary‐diagenetic coupling mechanism: Fine‐grained sedimentation facilitated intense mechanical compaction, whereas late‐stage carbonate cementation caused substantial porosity loss, solidifying the tight nature of the formation. Hydrocarbon accumulation follows a “densification before accumulation” model, driven by an overpressure difference of 6–7 MPa generated by the underlying Chang 7 source rocks, which facilitated migration through microfractures into the tight sand bodies. To address the challenge of identifying thin, low‐resistivity oil layers, Walsh inversion and resolution matching techniques were employed to enhance logging signal precision. On the basis of core‐log calibration, a quantitative identification standard was established, defining low‐efficiency oil layers by an acoustic transit time and deep resistivity . Despite their marginal petrophysical properties, the reservoirs exhibit a high brittleness index (&gt;60%) and low horizontal stress difference, indicating that large‐scale volume fracturing is a viable strategy for commercial development.

Hydraulic fracturing technology is key for shale gas development. The effectiveness of hydraulic fracturing is considerably affected by the characteristics of natural fractures within the reservoir, whereas shale fractures are considerably controlled by tectonic location. Therefore, understanding the development characteristics of natural fractures and their effects on the propagation of hydraulic fractures, even when natural fractures are effectively exploited, is critical for optimizing fracturing effects. Within this context, by examining the Longmaxi Formation in the Luzhou area in southern Sichuan in a case study, the development patterns and factors that control fractures in faulted anticlines, slopes and synclines are systematically analyzed through core and thin section observations, numerical simulations, and microseismic monitoring. The effects of different fracture characteristics on the propagation of hydraulic fractures and fracturing efficiency were investigated. The results revealed that (1) the fracture density in the study area decreases in the order of faulted anticlines, slopes and synclines; faulted anticlines are dominated by high-angle shear fractures and fault-associated fractures, which are characterized by high density, long propagation, and satisfactory connectivity, easily forming a network of fracture systems. Slopes are dominated by medium- to low-angle shear fractures, which are mostly arranged in parallel, and synclines are characterized by well-developed medium- to high-angle shear fractures intersecting with shale bedding-parallel fractures. The difference in the tectonic stress field is the main cause of the morphology and scale of fractures at different tectonic locations. (2) High-angle fractures are readily activated by hydraulic fracturing and extend horizontally, thereby forming a complex fracture network, which results in the optimal degree of fracturing stimulation; the hydraulic spreading effect is optimal when the fracture lengths range from 20 to 40 cm, whereas excessively long or short fractures limit vertical or horizontal propagation. The combination of horizontal and vertical fractures can enhance lateral propagation and vertical connectivity, which increases fracturing efficiency. (3) Fracture characteristics dominate the fracturing effect at different tectonic locations: in the syncline area, because shale bedding-parallel fractures intersect high-angle fractures and the fracture length is optimal, the fracturing stimulation area is the largest. Microseismic monitoring revealed that the propagation paths of hydraulic fractures are highly consistent with the simulation results, which validates the coupling mechanism among tectonic location, natural fractures and fracturing effectiveness. This study provides a geological basis for optimizing well placement and fracturing design in the Longmaxi Formation shale gas reservoir, Luzhou area, by highlighting the superior gas potential of syncline structures.

CO2 injection is critical for enhancing shale gas recovery, yet the competitive adsorption mechanisms between CO2 and CH4 in fracture systems remain unclear. This study integrates nuclear magnetic resonance (NMR) experiments with numerical modeling to investigate CO2/CH4 competitive adsorption in fractured shale. Wire-cut cores with controlled fractures were used in online NMR displacement tests, establishing a quantitative relationship between the fracture surface area ratio and methane adsorbed capacity. A novel layered CO2 injection model was developed, incorporating fracture and competitive adsorption effects. Results demonstrate that CO2 enhances methane desorption, converting adsorbed methane into free and confined states, as evidenced by opposing trends in the NMR signals. Numerical simulations further reveal that a stratified injection strategy increases gas production by 11.54% compared to commingled injection. Considering competitive adsorption at a fracture surface area ratio of 0.45 also improves the CO2 storage capacity by 9.10%. Field implementation should prioritize enhancing fracture development, followed by increasing the CO2 injection rate and high-permeability streak permeability, to maximize storage performance. This study provides a theoretical and experimental foundation for optimizing stratified CO2 injection into shale reservoirs.

To effectively manage the elevated pressure and flow rates encountered in the initial stages of shale gas extraction, throttling often is employed to modulate these parameters and mitigate bottom-well pressure losses. A mixed-integer nonlinear programming (MINLP) model is proposed that synergistically integrates a correlation mechanism between wellhead pressure and production rate and throttling disturbance constraints with shale gas system pressurization optimization. The model, guided by a cost-minimization objective function, incorporates pipeline pressure, flow rate limitations, compressor specifications, and throttling disturbance constraints. Empirical validation, based on a 2-year timeline, indicated that the optimization strategies produced by the coupled throttling disturbance framework offer superior and more economically efficient solutions than conventional methods. Compared with the actual pressurization scenario, the optimized scheme operated with 245 kW less power, the daily volume of gas handled by the compressor was reduced by 370,000 m3, and the compressor unit cost was CNY 266×104 less, and it centralized pressurization locations. This work demonstrates that the integrated throttling disturbance and correlation mechanism between pressure and production rate serves as a robust tool for optimizing pressurization schemes in shale gas operations.