Ping Yue

Fracture–vuggy carbonate reservoirs contain discrete caves, fractures, conduits, and vugs, which makes recoverable-reserve evaluation strongly dependent on connected volume rather than on total pore volume alone. This study develops a unit-scale dynamic reserve-updating method for the S48 unit, Tahe Oilfield, by coupling a water-body-corrected material-balance equation, a heterogeneity-corrected waterflood characteristic curve, and iterative geological-model calibration. The main methodological contribution is to convert static fracture–vug architecture into dynamically constrained connected subsystems: the parameter Rwo quantifies connected/injected water volume at the fracture–vug unit scale, whereas the coefficient M corrects the apparent slope of waterflood curves for non-uniform sweep and preferential pathways. The revised workflow was calibrated against pressure, production, injection-response, and history-matched simulation data. Sensitivity analysis indicates that the estimated reserve-utilization degree increased from 48.77% +/− 4.8 percentage points during natural depletion to 74.1% +/− 6.7 percentage points after gas injection, reflecting staged reserve mobilization within the tested uncertainty range. The method is intended for field-scale reserve updating in reservoirs with sufficient pressure-production data; its transferability remains limited by static-model quality, channeling intensity, and the single-unit validation scope of this study.

During drilling in fractured formations, wellbore instability issues such as fluid loss and collapse frequently occur, severely compromising drilling safety. Traditional criteria such as Mohr–Coulomb often fail to adequately account for fracture effects, leading to inaccurate collapse pressure predictions. Taking the Tahe Oilfield as a case study, this research develops an enhanced model for predicting wellbore collapse pressure in fractured formations. Based on principles of elastic mechanics and Biot’s effective stress theory, a stress distribution model around deviated wellbores is established. The single weak plane strength criterion is integrated with the Mohr–Coulomb criterion to characterize failure mechanisms in both fractured zones and intact rock matrix. Newton’s iterative method, implemented in MATLAB, is employed to solve for collapse pressure, and a sensitivity analysis is conducted to evaluate the influence of factors such as in situ stresses and fracture orientation. A case study from Well THX demonstrates that neglecting fractures results in a symmetrical collapse pressure profile and an unduly narrow safe mud weight window. In contrast, accounting for fractures significantly increases the required mud weight and identifies an optimal azimuth range for enhancing wellbore stability. The Mohr–Coulomb criterion is shown to underestimate the necessary mud weight, which aligns with actual wellbore collapse incidents encountered during drilling. The single weak plane criterion offers more accurate predictions, recommending a higher minimum mud density and an optimized well trajectory to mitigate drilling risks. These findings offer theoretical and practical guidance for mitigating wellbore instability in fractured formations.

Multi-stage fractured horizontal wells (MSFHWs) represent a crucial development approach for low-permeability reservoirs, where accurate productivity prediction is essential for production operations. However, existing models suffer from limitations such as inadequate characterization of complex flow mechanisms within the reservoir or computational complexity. This study subdivides the flow process into three segments: matrix, fracture, and wellbore. By employing discretization concepts, potential distribution theory, and the principle of potential superposition, a productivity prediction model tailored for MSFHWs in low-permeability reservoirs is established. Moreover, this model provides a clearer characterization of fluid seepage processes during horizontal well production, which aligns more closely with the actual production process. Validated against actual production data from an offshore oilfield and benchmarked against classical models, the proposed model demonstrates satisfactory accuracy and reliability. Sensitivity analysis reveals that a lower Threshold Pressure Gradient (TPG) corresponds to higher productivity; a production pressure differential of 10 MPa yields an average increase of 22.41 m³/d in overall daily oil production compared to 5 MPa, concurrently reducing the overall production decline rate by 26.59% on average. Larger stress-sensitive coefficients lead to reduced production, with the fracture stress-sensitive coefficient exerting a more significant influence; for an equivalent increment, the matrix stress-sensitive coefficient causes a production decrease of 1.92 m³/d (a 4.32% decline), while the fracture stress-sensitive coefficient results in a decrease of 4.87 m³/d (a 20.93% decline). Increased fracture half-length and number enhance production, with an initial productivity increase of 21.61% (gradually diminishing to 7.1%) for longer fracture half-lengths and 24.63% (gradually diminishing to 5.22%) for more fractures; optimal critical values exist for both parameters.

This paper provides a comprehensive analysis of gas field produced water from four perspectives: water sources, chemical composition, treatment methods, and application scenarios. It identifies critical challenges in current formation reinjection practices, including poor containment performance for injection layers, difficulties in optimal layer selection, and uncertainties in injection volume determination. To address these issues, systematic selection criteria for reinjection layers were established. Taking a depleted gas reservoir in the Ordos Basin as a case study, we conducted a geological analysis of candidate formations based on previous research findings. We set up three groups of schemes regarding injection wells, injection rate, and permeability inhomogeneity and studied reservoir reinjection water volume, reinjection formation pressure, reinjection waves and range, and reinjection safety using three-dimensional numerical simulation technology. Finally, we selected the preferred scheme of reinjection well location in consideration of permeability inhomogeneity, with a cumulative reinjection volume of 1554.3 × 10⁴ m³ and a change in reinjection formation pressure of 0~20 MPa. The pressure change in the upper overburden of the reinjection layer was kept within 3 MPa, a value consistent with actual historical reinjection data, confirming again the accuracy of this layer selection strategy and the aforementioned layer selection analysis and providing a basis for layer selection and reinjection safety for the assessment of recovered water reinjection in other unconventional gas reservoirs.

After several rounds of water injection, the secondary oil-water interface in the fracture-vuggy reservoirs in the Tahe oil field is uplifted, resulting in the gradual deterioration of the effect of water injection on oil replacement, and it is beginning to be explored that the formation energy can be supplemented by gas injection to increase the synergy and improve the efficiency of replacement. Aiming at the problem of the unknown development strategy of late adjustment of typical gas injection wells in the Tahe oilfield, this paper establishes the criteria for judging different gas injection well patterns and proposes five typical gas injection well patterns: cave + side secondary, cave + penetrating deep and large fracture, fracture + cave reservoir, surface weathered crust + cave pattern, and dark river + upper hall cave pattern. Based on the grey correlation degree and group decision hierarchy analysis method, the main controlling factors analysis model was established, and the main controlling factors of the five models were analysed by numerical simulation. The results show that: in the cave + side secondary gas injection mode, the main controlling factors are the fracture distance and the permeability, with influence degrees of 26.98% and 26.75% respectively on the gas injection effect; in the cave + penetrating deep and large fracture gas injection mode, the main controlling factor are the permeability of the fracture and water size, with influence degrees of 29. 82% and 29.70%, respectively; in the fracture + cave reservoir gas injection mode, the main controlling factor is the permeability of the fracture, with an influence degree of 38.84%; the main controlling factor of the surface weathered crust + cave pattern gas injection well model is the permeability of the weathered crust, with a degree of influence of 35.65%; the main controlling factor of the dark river + upper hall cave pattern gas injection well model is the size of the water body, with a degree of influence of 39.45%. The main controlling factors and the dynamic and static characteristics of each different gas injection well pattern can provide guidance for the adaptive strategy of subsequent development of the same type of fracture-vuggy reservoirs.

As the main method of secondary development, water injection has been widely used in fractured vuggy carbonate reservoirs. By using an evaluation index system combined with an integrated approach to objectively evaluate and support targeted and operational adjustments of water injection development effects in fractured vuggy carbonate reservoirs, a comprehensive evaluation method is established in this study. The CRITIC method is used as the main approach, and the analytic hierarchy process, the entropy weight method, and the coefficient of variation method are used as sub-methods. Additionally, the clustering centres are divided using the clustering method to reduce the error caused by the irrational distribution of the relevant evaluation index data. The method is used to evaluate and analyse the effects of water injection development, using the F_I7 fault zone of the Halahatang oilfield as an example. The application results show that the evaluation method is feasible and effective for cases with small data volume, fewer computational resources, and less time. This study has a certain reference significance for the evaluation of the effect of water injection development in similar fractured vuggy reservoirs.

Identifying and categorizing drilling-induced fractures is pivotal for understanding the mechanisms underlying wellbore instability, drilling fluid loss, and assessing reservoirs using imaging logging data. This study employs a linear elastic stress model around the wellbore, coupled with a tensile failure criterion, to establish a predictive framework for the orientation of drilling-induced fractures. It investigates how engineering parameters like wellbore trajectory and bottomhole pressure influence the distribution of principal stresses around the wellbore, as well as the angle and orientation of drilling-induced fractures relative to the wellbore axis, across various faulting scenarios. The results indicate that drilling-induced fractures exhibit structured arrangements and consistent patterns, often appearing at approximately 180° symmetric intervals and descending in similar orientations. This provides a theoretical basis for their systematic identification and classification. Under different stress conditions, these fractures can manifest as feather-like shapes, “J”-shaped, or transitional states between feather-like and “J”-shaped orientations, as well as “V”-shaped or “M”-shaped orientations. Accurate detection and classification of these fractures are essential for interpreting effective fractures, conducting thorough reservoir evaluations, and predicting appropriate drilling fluid densities to mitigate the wellbore failure risk. Moreover, this knowledge aids in effectively determining the magnitude and direction of in situ stress inversion.

In order to limit the increase in global average temperature to 1.5°C, it is necessary to reduce carbon dioxide (CO₂) emissions by 45% by 2030. CO₂ capture, utilization and storage (CCUS) is one of the effective ways to reduce CO₂ emissions. Geological storage of CO₂ provides a solution with the lowest economic cost and the fastest effect for reducing CO₂ emissions. This article proposes a CO₂ storage regional division method based on the characteristics of low‐permeability reservoirs in the Yanchang W oilfield in China. The storage space is divided into four regions: gas phase region, two‐phase or near‐miscible region, diffusion region, and oil phase region. As the displacement progresses, the volume of the gas phase region and the two‐phase or near‐miscible region gradually increases; the volume of the diffusion region first increases and then decreases. By calculating the storage capacity of each region separately, the total storage capacity is finally calculated. The impact of different pressures and injection rates on dynamic CO₂ storage capacity was evaluated. The results show that pressure and injection rate are positively correlated with total storage capacity. When CO₂ miscible conditions are reached, the increase in total storage capacity will significantly decrease. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.