Due to their low permeability, the location of natural fractures is key to the successful development of buried hill reservoirs. Due to the high degree of rock fragmentation and strong absorption of seismic waves at the top of buried hill formations, it is hard to identify the distribution of natural fractures inside a buried hill using conventional seismic methods. To overcome this difficulty, this study proposes a natural fracture identification technology for buried hill reservoirs that combines a continuum damage mechanics model with finite element numerical simulation. A 3D numerical solution workflow is established to determine the natural fracture distribution in target buried hill reservoirs. By constructing a geological model of a block, reconstructing the orogenic history, developing a 3D finite element model, and performing numerical simulations, the multi-stage orogenic processes experienced by buried hill reservoirs and the resultant natural fracture formation are replicated. This approach yields 3D numerical results of natural fracture distribution. Using the G-Block in the Zhongyuan Oilfield as a case study, the natural fracture distribution in a buried hill reservoir composed of mixed lithologies, including marble and Carboniferous formations, within the faulted G6-well group is analyzed. The results include plane views of the contour of damage variable SDEG, which represents the fracture distribution within the subsurface layer at 600 m intervals below the buried hill surface, as well as a vertical sectional view of the contour of SDEG’s distribution along specified well trajectories. By comparison with the results of the fracture distribution obtained with logging data, a consistency of 87.5% is achieved. This indicates the reliability of the numerical results for natural fractures obtained using the technology presented here.

Natural fracture development in tight-sand gas reservoirs is strongly controlled by tectonic evolution yet remains difficult to characterize using conventional seismic interpretation due to limited resolution. This study presents a damage-mechanics-based approach that integrates 2D seismic data, well logs, and drilling information to construct a 3D geological model and simulate tectonically induced fracture development under regional orogenic loading. The approach is applied to the Permian formation in the Ordos Basin. Modeled damage zones, interpreted as areas of enhanced natural fracture development, show strong spatial correspondence with high-productivity wells. The results demonstrate that damage mechanics provides an effective framework for linking tectonic processes with fracture distribution in tight-sand reservoirs and offers new insights into fracture-controlled gas accumulation and productivity. This case demonstrates the applicability and effectiveness of the technology of continuum damage mechanics for 3D natural fracture distribution based on sets of 2D seismic data plus drilling data. Although sets of 2D seismic data cannot replace real 3D seismic data for all its usage, it can produce numerical results of natural fractures with reasonable accuracy for calculation of natural fractures with damage mechanics method.

The Wumishan Formation carbonate buried-hill reservoir in Hejian, Jizhong Depression, is a key geothermal reservoir where natural fractures control high-yield production. However, sparse control wells and seismic attribute non-uniqueness render conventional manual fusion subjective, while complex models tend to overfit under small-sample conditions. This study presents a well-controlled seismic multi-attribute fusion method that uses four-level (I–IV) well-log reservoir fracture interpretation as supervised calibration labels to predict 3D reservoir fracture distribution. Using 3D seismic data and comprehensive well-log fracture interpretation from wells JR1-1 and JR1-6, more than ten fracture-sensitive attributes were computed and systematically compared against well fracture grades through well-seismic calibration. Three complementary attributes—high-resolution eigenvalue coherence, maximum principal component curvature, and maximum likelihood similarity enhancement—were selected as primary fusion channels. An ordinal logistic regression model was then trained on the well-calibrated samples, jointly solving feature weights and ordinal cumulative classification thresholds within a unified likelihood framework to map seismic features onto the four-level reservoir fracture classification. Application to the target block shows that data-driven attribute weights are consistent with expert manual weights, and leave-one-well-out cross-validation yields 80.5–84.1% reproducibility (Kappa = 0.744). The resulting reservoir fracture distribution exhibits pronounced spatial zonation and vertical segmentation, with dominant fractures concentrated at structural highs on the reservoir top surface. This method provides a robust, well-controlled framework for natural fracture characterization and can guide geothermal well target optimization and reservoir stimulation design in deep geothermal fields.

Accurate determination of rock mechanical parameters for ultra-deep carbonate reservoirs (>9000 m) is critical for wellbore stability evaluation and acid-fracturing parameter optimization, yet systematic experimental data for such depths remain scarce. This study investigates grainstone cores from the YS Section (9199.8–9624.0 m) of Well XY in the Tarim Basin using continuous scratch tests—a minimally destructive method providing continuous strength profiles—complemented by conventional uniaxial compression tests. Five working conditions are systematically compared: original (unsoaked) state, drilling-fluid instantaneous contact (0 h), fresh water immersion (24 h), drilling-fluid immersion (24 h), and 15% hydrochloric-acid immersion (24 h). In the original state, scratch-test averages yield a uniaxial compressive strength (UCS) of 179.9 MPa, internal friction angle of 34.2°, and cohesion of 47.6 MPa. None of the three water-based working fluids causes measurable strength degradation within 24 h, with UCS values of 191.6, 186.0, and 190.9 MPa, respectively, attributable to the low water sensitivity of carbonate minerals. In contrast, 24 h acid immersion reduces UCS to 109.2 MPa (−39.3%), cohesion to 29.0 MPa (−39.0%), and internal friction angle to 27.1° (−20.6%), driven by intergranular cement dissolution, with strong sample-dependent variability (individual UCS reductions ranging from 12.6% to 48.0%). Scratch depth significantly influences results: UCS at 0.20 mm depth is 30.3% lower than at 0.18 mm. Calibration against rigid-testing-machine UCS yields a ratio coefficient α = 0.47~0.61. A value of 0.56 is set for α, giving a recommended engineering UCS of 100.7 MPa. These findings provide an experimental basis for wellbore stability analysis and acid-fracturing design in ultra-deep carbonate reservoirs.

Natural fractures play a key role in controlling fluid flow and heat extraction in carbonate geothermal reservoirs. Due to the high degree of rock fragmentation and strong seismic wave absorption at the top of the carbonate formation, it is difficult to identify the distribution of natural fractures inside the carbonate formation using conventional seismic methods. Additionally, the heterogeneous distribution of permeability and porosity in the geothermal reservoir remains a challenge for the numerical simulation of the geothermal production process. To overcome these difficulties, this study uses the damage mechanics approach to characterize the distribution of natural fractures generated by orogeny in the Wumishan Formation of the JR block. Based on the derived damage field, a finite element model for the geothermal reservoir with spatially heterogeneous porosity was constructed, and empirical relationships between damage variable values and values of permeability of the fractured geothermal reservoir were established. A thermo-hydro-mechanical (THM)-coupled finite element model was then employed to evaluate well transmissibility and porous flow behavior under specified injection–production pressure conditions. The flow capacities of 18 wells were quantified and ranked, providing a basis for optimizing the injection–production well layout. Optimization of well locations and injection–production functions was conducted considering alternating well placement, total flow balance, and target well ratios (1:1 and 3:2). By adjusting well functions and locations, the total injection and production rates were balanced under the given pressure conditions, with the total injection and production capacities increased by 12.1% and 6.73%, respectively. The error tolerance used for convergence in numerical calculation is 2% for the THM model. Numerical results of temperature contours indicate the following: (1) There is no risk of thermal breakthrough with the planned design. (2) The temperature at the wellhead of production wells ranges from 92 °C to 105 °C. The results demonstrate that the combined application of damage mechanics and THM-coupled modeling provides an effective framework for accurately characterizing natural fractures and optimizing injection–production strategies in fractured carbonate geothermal reservoirs.