Search Results (449)

The Ordovician strata in Northern Tarim host extensively developed carbonate karst reservoirs that contain abundant hydrocarbon resources. However, owing to extreme burial depths, pronounced heterogeneity, and limited seismic resolution within the Tarim Basin, the diagenetic fluid types and their specific influences on reservoir development remain poorly understood. Consequently, this study integrates core observation, thin-section identification (TSI), cathodoluminescence (CL), scanning electron microscopy (SEM), X-ray diffraction (XRD), stable isotopes (C, O, Sr), trace and rare earth elements (REE), fluid inclusion analysis (FIA), and in situ laser U-Pb dating (U-Pb). This multifaceted petrographic and geochemical approach characterizes the macro- and microscopic geological features of these karst reservoirs. By elucidating the types, timing, and phases of diagenetic fluids, this research evaluates fluid-driven impacts on reservoir quality and establishes a comprehensive genetic model for reservoir evolution. Results identify five distinct tectonic fracturing phases. Phases 1, 2, and 4 involved calcite infilling precipitated from seawater and meteoric freshwater, with fluid inclusion homogenization temperatures of 62–87 °C, 57–91 °C, and 94–126 °C, formed during the Caledonian–Hercynian, Early Hercynian, and Indosinian–Yanshanian periods, respectively. Phase 3 featured hydrothermal dolomite infilling during the Hercynian, with fluid inclusion homogenization temperatures ranging from 128 to 163 °C, whereas Phase 5 remained unfilled during the Himalayan. Constrained by the U–Pb age interval of 445.2–436.5 Ma acquired from vug-filling calcite together with cross-cutting petrographic relationships, multi-stage meteoric freshwater dissolution mainly occurred from Middle Caledonian Episode III (447–443.7 Ma) to the Early Hercynian (460–359 Ma). Reservoirs within the Penglaiba–Lower Yingshan Formations underwent a complex evolution comprising syngenetic-to-early diagenetic pore development, Middle Caledonian–Early Hercynian weathering crust karstification and dedolomitization, and Late Hercynian hydrothermal dissolution-infilling, ultimately resulting in the formation of tectonic-karst composite reservoirs. Full article

To clarify how shale-reservoir heterogeneity constrains hydraulic-fracturing effectiveness in complex structural areas, this study analyzes exploration well X in the Mugan–Shoushan area, Yunnan Province, using organic geochemistry, petrology and mineralogy, reservoir-property, and rock-mechanical data from the Wufeng–Longmaxi formations. The results show pronounced vertical engineering-geological differentiation. Average clay content decreases from 42% to 8%, Average carbonate minerals increase from 16% to 50%, and quartz is anomalously enriched in the Longyi 1-1 layer of the Longmaxi Formation (Longyi 1-1; 76%). The Longyi 1-3 layer of the Longmaxi Formation has the highest porosity (9.37%) but low matrix permeability (0.013–0.019 mD); the Longyi 1-2 layer of the Longmaxi Formation is highly brittle and tight; and the Longyi 1-4 layer of the Longmaxi Formation is highly ductile and water-rich. Accordingly, four engineering geological facies are defined: Type I, organic-rich, moderately brittle, and moderately ductile composite facies; Type II, organic-rich, highly brittle, tight, and strongly stress-sensitive facies; Type III, organic-poor, highly ductile, water-rich, and strongly water-sensitive facies; and Type IV, highly brittle, fracture-developed, and high-adsorption facies. Implications for fracturing are proposed for each facies, including mixed-fluid network stimulation, acid pretreatment with controlled flowback, interval avoidance, and coordinated stimulation with adjacent main reservoirs. Full article

The microstructures and torsional fracture morphologies of S2 alloy steel screwdriver bits were characterized by scanning electron microscopy (SEM). The bits were oil-quenched from 830 °C and 860 °C and subsequently tempered at 150 °C and 170 °C under three carbon potential levels (0.35, 0.40, and 0.45). In parallel, Deform-3D and Ansys Workbench were employed to simulate and compare the microstructure evolution during quenching, the residual stress field after quenching and tempering, and the stress distribution developed under torsional loading. The results reveal that the non-planar fracture and low qualification rate of the bits arise from two independent but synergistic mechanisms: (1) insufficient austenitizing at 830 °C fails to produce fully uniform austenite, resulting in non-uniform martensitic microstructure and inhomogeneous hardness distribution after quenching; (2) low furnace carbon potential (≤0.35) causes surface decarburization and the formation of massive ferrite at the near-surface region, which acts as preferential crack initiation sites. Furthermore, the transformation stress generated during quenching, the residual stress remaining after tempering, and the stress concentration at tooth edges under service loading jointly promote crack initiation and propagation. A uniform, high-hardness tempered martensite microstructure is obtained when the bits are austenitized at 860 °C with the carbon potential strictly maintained between 0.40 and 0.45, held for 60 min before oil quenching, and air-cooled after tempering at 170 °C. This optimized heat-treatment route eliminates surface decarburization, ensures microstructural homogeneity, reduces residual stress, and enables the bits to fail by planar fracture under torsional load with 100% qualification rate. Full article

The exploration of oil and gas resources is shifting toward ultra-deep and extra-deep reservoirs, including in the Tarim Basin, where various types of carbonate rocks are buried. Owing to the extreme burial depths, the mechanical behavior of these rocks under extra-deep conditions differs significantly from that of shallow formations, making it essential to understand their mechanical responses. This study investigated the mechanical properties and failure modes of carbonate rocks, specifically dolomite, argillaceous limestone, and pure limestone. Samples from extra-deep formations were initially analyzed for mineral composition and microstructure, after which uniaxial and triaxial compression tests were conducted to evaluate strength, static elastic modulus, and axial strain at peak stress. The results indicate that dolomite exhibits the highest mechanical strength and stiffness among the three lithologies. Under conditions of a high confining pressure of 100 MPa and a temperature of 160 °C, its elastic modulus and triaxial compressive strength are 65.4 GPa and 611.2 MPa, respectively, compared with 52.8 GPa and 444.2 MPa for limestone. Strength increases with confining pressure for all lithologies, with dolomite showing the most pronounced strengthening response. Although elevated temperature reduces rock strength, its effect is weaker than that of confining pressure. The failure mode is strongly controlled by confining pressure. At low confining pressures, failure is dominated by localized shear bands and brittle fracturing, whereas increasing confining pressure promotes a transition toward quasi-brittle deformation or ductile plastic flow. Dolomite predominantly maintains a quasi-brittle failure mode, argillaceous limestone exhibits a clear brittle-to-ductile transition, and pure limestone shows the greatest tendency to develop ductile plastic flow under high confining pressure conditions. The results further demonstrate that mineral composition and microstructural characteristics play critical roles in controlling the deformation and failure mechanisms of carbonate rocks. High-calcite pure limestone can exhibit ductile-like deformation behavior due to cataclastic processes, allowing significant strain without localization failure. These insights enhance understanding of carbonate rock behavior under extra-deep formations, informing practical applications in geology science. Full article

Upper-loss and lower-kick (UL–LK) events may occur in ultra-deep fractured carbonate formations when gas enters from a lower high-pressure zone while drilling fluid is lost to an upper low-pressure fracture. Because both flows can continue after shut-in, the wellbore remains incompletely closed. This study develops a transient wellbore-formation pressure model based on phase mass conservation and global volume balance, and introduces an effective gas–liquid partition coefficient to represent phase separation at the fracture inlet. The model shows that circulation loss limits bottomhole-pressure recovery, allowing gas influx to persist after shut-in. Relative to kick-only conditions, UL–LK conditions have a lower initial shut-in casing pressure (SICP) but a steeper subsequent buildup. A smaller partition coefficient, corresponding to preferential liquid loss, leaves more free gas in the wellbore and further increases the SICP buildup rate. A surface-pressure-based screening method was developed from contrasting SICP and shut-in drillpipe pressure (SIDPP) responses. When applied to five field cases, the method correctly identified three UL–LK cases and two kick-only cases. Its outcomes for five field cases agreed with the field interpretations. This framework supports post-shut-in pressure prediction and rapid screening without dedicated downhole measurements. Full article

Ultra-deep lattice-like fractured carbonate reservoirs, formed by multi-period tectonic movements, feature strong heterogeneity, multi-scale fracture nesting, and anisotropic in situ stress. However, hydraulic fracture (HF) propagation behaviors within these complex formations remain poorly understood. In this study, using an unstructured fracture network approach, we simulated HF propagation in two typical fault-controlled lattice-like structures: compressive-torsion and pull-apart overlap zones. The performance of commingled, staged, and temporary plugging fracturing was evaluated, alongside sensitivity analyses of wellbore orientation, plugging timing, pump rate, and fluid viscosity. Results indicate that HFs in compressive-torsion zones exhibit long, straight geometries with local tensile activation points. Conversely, pull-apart overlap zones promote step-shaped, multi-branched fractures with superior lateral connectivity. The optimal timing for temporary plugging exhibits a delayed trend with increasing natural fracture density, ranging from 50% to 70% of the fracturing process in compressive-torsion zones, whereas an earlier implementation is preferred in pull-apart overlap zones, occurring at 33–65% of the fracturing process. Furthermore, HFs in compressive-torsion zones are less sensitive to viscosity and pump rate. To optimize stimulated volume, a moderate viscosity of 50–60 mPa·s is universally recommended. Regarding pump rates, 8–10 m³/min is ideal for balanced connectivity in pull-apart overlap zones, whereas >12 m³/min is required for compressive-torsion zones. These findings provide critical theoretical and engineering guidelines for differentiated fracturing strategies in ultra-deep reservoirs. Full article

In this study, a rapid analytical framework is developed for reconstructing transient formation-pressure distributions in sparsely connected fractured-vuggy carbonate reservoirs using well-test-derived fracture–cave geometry and source allocation. Pressure–flow relationships are established for caves, fractured bodies, and finite line-source fractures; unit-source solutions are combined via spatial superposition and Duhamel convolution for variable-rate production; and the framework is evaluated by comparing Well EX-1 against a PEBI-grid simulation. Cave response is derived from mass conservation and effective compressibility, while point- and line-source Green’s functions describe pressure diffusion. For the 30-day EX-1 case, analytical and PEBI pressures at four locations show close internal agreement, with a mean absolute error of 0.070 MPa, a root-mean-square error of 0.083 MPa, and a maximum absolute error of 0.13 MPa. This method is applicable mainly to single-phase, slightly compressible, linear-flow conditions with a constrained fracture–cave topology. It provides a rapid screening tool for deep carbonate reservoirs with sparse well control, while multiphase, strongly nonlinear, reactive, or geomechanically coupled cases require conventional numerical simulation. Full article

Ultra-deep Ordovician carbonates in the Tarim Basin are a major target for oil and gas exploration in China. Localized overpressure, however, creates substantial well-control risks and impairs drilling safety and exploration performance. This study investigates the Fudong Block of the Fuman Oilfield using drilling, seismic, and well-test data. We develop a high-resolution, layer-specific formation-pressure prediction workflow that integrates well and seismic data through a stress–fracture-pressure framework. The workflow combines geomechanical modeling, prediction of the in situ stress field and fracture distribution, stress-fracture matching, Biot-theory-based pressure prediction, and iterative calibration against drilling observations. The results show that: (1) overpressure is concentrated near secondary faults, branch faults, and NW-trending faults. It is jointly controlled by tectonic compression, pressure retention within fracture–vug bodies, and fluid charging. Multiple vertically separated pressure systems are common, and their marked heterogeneity is closely related to secondary-fault development and fracture–vug connectivity; (2) drilling disturbance can generate apparent overpressure and lead to erroneous pressure interpretation. Overpressured wells commonly exhibit a kick followed by lost circulation or simultaneous kick and loss. Drilling-fluid invasion into confined fracture–vug bodies causes pressure buildup; and (3) formation pressure is a key parameter in integrated geological and engineering sweet-spot evaluation and is closely linked to wellbore stability. Field applications confirm the accuracy of the proposed workflow. The method strengthens integrated geology-engineering evaluation and provides a practical basis for the safe and efficient development of ultra-deep carbonate reservoirs. Full article

This study systematically investigates the effects of gold tailings (GT) sand substitution levels and particle fineness on the rheological behavior, mechanical properties, and microstructural characteristics of Engineered Cementitious Composites (ECC). The results demonstrate that incorporating moderate amounts of GT sand (≤75%) effectively enhances both the compressive strength and fracture toughness of the composite. However, complete substitution (100% GT) significantly increases matrix porosity, leading to a consequent reduction in comprehensive mechanical strength. A critical size-dependent decoupling effect was observed: while the full replacement of fine aggregates with coarse GT severely degrades compressive strength due to excessive void formation, it unexpectedly increases the matrix fracture toughness by inducing significant crack deflection and tortuosity. Conversely, the incorporation of fine GT optimizes the distribution of matrix flaws and fosters a stable fiber pull-out mechanism. Consequently, despite a reduced pseudo-strain hardening (PSH) index, the fine GT-blended ECC achieves a remarkable tensile ductility of up to 3.0% by satisfying the fundamental multiple-cracking energy criteria while maximizing frictional energy dissipation. Furthermore, substituting natural silica sand with GT yields a highly sustainable composite, reducing carbon dioxide emissions by 41% and material costs by 20% without compromising core mechanical performance. Full article

Deep complex carbonate reservoirs contain different types of pore space, including vugs and fractures. Their gas–water distributions and flow characteristics are complex. The effect of pore structure and gas–water flow on resistivity in deep complex carbonate reservoirs remains unclear. This uncertainty creates challenges for natural gas exploration and development. A gas–water displacement and impedance synchronous measurement platform was established. Three types of glass-etched micromodels were fabricated from CT images of real carbonate cores. These models included a fracture–vuggy type with large aperture, a fracture–vuggy type with small aperture, and a vuggy type. After the micromodels were saturated with dyed formation water, gas–water displacement and water–gas displacement were conducted sequentially. Microscopic images of gas–water distribution, water saturation, resistivity, and resistivity index were obtained. The results showed that gas preferentially entered connected fractures and large pore throats, forming preferential channels. Residual water was mainly retained in vug corners, narrow throats, and weakly connected zones. During gas–water displacement, resistivity increased as water saturation decreased. The resistivity response showed a three-stage pattern of slow increase, rapid increase, and subsequent slow increase. During water–gas displacement, resistivity decreased as water saturation increased. The resistivity response showed a three-stage pattern of slow decrease, rapid decrease, and subsequent slow decrease. All three models exhibited non-Archie behavior. The stage-specific saturation exponent n ranged from 2.62 to 13.10, 4.36 to 7.24, and 5.37 to 9.84 for the fracture–vuggy type with large aperture, fracture–vuggy type with small aperture, and vuggy type, respectively. Their overall n values were 7.26, 6.36, and 5.39, showing that the fracture–vuggy type with large aperture had the most abrupt electrical response. This study clarified the relationship between gas–water flow characteristics and conductive response in carbonate rocks with different pore structures. The results provide pore-scale experimental evidence for water-invasion identification, remaining gas evaluation, and calibration of rock electrical parameters in complex carbonate reservoirs. Full article

Enhancement of carbon dioxide (CO₂) storage capacity in subsurface formations aids in offsetting the projected increase in carbon emissions. Consequently, various injection techniques should be explored to optimize the storage process. This study delves into CO₂-foam utilization in a saline carbonate aquifer for underground carbon storage (UCS) purposes. In order to depict the subsurface flow dynamics, a carbonate saline aquifer model, which incorporates heterogeneous properties, a natural fracture network, and geochemical reactions, was developed. Various subsurface flow dynamics were considered by generating multiple natural fracture network realizations. Afterward, the developed model was utilized to numerically simulate the UCS process for two hundred years, capturing the CO₂ inventory as well as fluid–fluid and fluid–rock interactions throughout the storage process. Introducing the foam enabled the injected CO₂ to penetrate deeper around the injection zone; hence, higher trapped CO₂ can be expected at the bottom of the aquifer. Despite the heterogeneity and natural fractures, CO₂ foam helped in enhancing the dissolved CO₂ distribution in the swept volume of the aquifer. The natural fracture network realizations demonstrated that the CO₂ foam can potentially limit the influence of natural fractures during the UCS process. Furthermore, the subsurface geochemical reactions tend to be altered due to the drop in the fluid–fluid and fluid–rock interactions. Overall, the findings suggest that CO₂ foam impacts surpass the heterogeneity and natural fracture network effects during the UCS. While the performed evaluation highlighted the CO₂ foam role within a carbonate saline aquifer, the workflow and outcomes of the study can be extended to various subsurface environments wherein a compatible CO₂ foam design can lead to CO₂ storage capacity enhancement. Full article

Carbonate gas reservoirs are characterized by strong heterogeneity and a complex combination of pores, fractures, and caves. The productivity of gas wells is controlled by many factors, including geology, development, and engineering factors. The traditional one-point productivity evaluation method is insufficient to accurately characterize the productivity differences in gas wells with different reservoir types. In this paper, the carbonate gas reservoir of the MK Formation in the HS 4 block is taken as the research object. Based on core characteristics, thin sections, dolomite content, and permeability data, the two main reservoir types, vuggy and fracture-vuggy, are systematically categorized. The influence of geological, development, and engineering factors on gas well productivity is analyzed using SHAP values. At the same time, to improve the accuracy and engineering practicability of gas reservoir productivity evaluation, the one-point productivity equation was refined, and open-flow capacity prediction charts for vuggy and fracture-vuggy reservoirs were constructed by combining the improved equation with the steady-state productivity equation. The results show that the dolomitization degree of vuggy reservoirs is lower than that of fracture-vuggy reservoirs, and the reservoir space types are mainly small dissolution pores or intergranular dissolution pores. The lithology of the fracture-vuggy reservoir is dolomite. The reservoir space of this type of reservoir is mainly composed of large dissolution pores and fractures, with a good matching relationship between fractures and pores. Based on the SHAP interpretation and analysis method, it is clear that cumulative water production, total acid fracturing fluid volume, gas-layer thickness, and porosity are the main factors affecting gas well productivity. Among them, the influence of cumulative water production and total acid fracturing fluid volume is the most significant, indicating that changes in the gas-water relationship and the effect of acid fracturing factors during development have a greater impact on gas well productivity. Based on the improved one-point productivity equation and the steady-state productivity equation, the open-flow prediction chart of vuggy and fracture-vuggy reservoirs is established. In predicting the gas well productivity of medium-deep reservoirs, with reconstruction scale and geological conditions similar to those of the HS 4 block, the chart’s predictions are in good agreement with field gas test and production test results. The single-well prediction error ranges from 2.2% to 6.5%, with an average error of 4.3%, indicating that the established chart has good applicability and predictive reliability. The research results can provide a theoretical and technical basis for reservoir classification evaluation, reasonable production allocation optimization, and new-well productivity prediction for carbonate gas reservoirs in the HS 4 block. Full article

China hosts abundant coal-rock gas (CRG) resources, which have become a critical unconventional natural gas contributor to national reserve expansion and production increment. Supercritical carbon dioxide (ScCO₂) fracturing is recognized as a green and efficient stimulation technology, exhibiting great potential for high-efficiency CRG exploitation. To clarify the effects and intrinsic mechanisms of ScCO₂ treatment on coal fracture initiation, propagation, and CRG recovery enhancement, true triaxial fracturing and CO₂-CH₄ displacement experiments were performed in combination with multiple microscopic characterization methods, including X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Scanning electron microscopy (SEM). The multi-scale experimental investigation systematically revealed the fracture development mechanism, permeability variation characteristics, and microstructural evolution of coal reservoirs under ScCO₂ interactions. The results indicate that ScCO₂ fracturing significantly lowers the coal fracture initiation threshold compared with conventional hydraulic fracturing, with the breakdown pressure reduced by 26.2% and the initiation time shortened by 37.5%. Such advantages facilitate coal fracture activation and the development of complex fracture networks. Long-term ScCO₂ soaking induces the dissolution of inorganic minerals (e.g., calcite, plagioclase, and clay minerals) and the extraction of inherent organic matter within coal matrices. The coupled hydro-chemical reactions reconstruct the coal pore structure, enlarge pore throats, and improve reservoir permeability, achieving a maximum permeability enhancement of approximately 1.6 times. Meanwhile, ScCO₂ displacement yields a prominent CRG recovery performance, with an ultimate gas recovery factor up to 93.85%. The CRG enhancement mechanism of ScCO₂ fracturing is comprehensively attributed to three core coupled effects. First, ScCO₂ dynamic fracturing generates intricate fracture networks, which greatly optimize reservoir seepage channels and flow space. Second, the ScCO₂–formation water–coal interaction modifies coal physical properties via mineral dissolution and organic matter extraction, thereby improving reservoir permeability. Third, the preferential adsorption of CO₂ over CH₄ triggers effective competitive adsorption and gas displacement, further promoting adsorbed methane desorption and elevating CRG recovery efficiency. This study provides a solid theoretical foundation for the field application of ScCO₂ fracturing technology and offers valuable insights into the green, efficient, and sustainable development of deep coal-rock gas resources. Full article

To clarify the composition and origin of the suspected solid bitumen, which is found in the fractures of the Jixian System in Tongcheng outcrops, the suspected solid bitumen samples, as well as dolomite samples, were collected from the Jixian System in Tongcheng and Qishan outcrops for various tests. The results show that the suspected solid bitumen samples are mainly composed of clay minerals. No solid bitumen was found in the pores and microcracks of the dolomite samples by microscope and Raman spectroscopy. The total organic carbon content of the solid bitumen ranges from 0.59% to 1.15%, revealing that the suspected solid bitumen is dark mudstone powder, rather than solid bitumen. The R_b values range from 2.59% to 2.77%, and the Ts/(Ts + Tm) values mostly approach 0.5, indicating that the organic matter in the suspected solid bitumen is in the mature to over-mature stage. The V/(V + Ni), Sr/Cu, and Sr/Ba values of the suspected solid bitumen indicate that it was deposited in a warm, humid, anoxic sedimentary environment. The slightly right-inclined rare earth element pattern of the suspected solid bitumen samples implies the sedimentation rate was slow or they were affected by weathering and leaching processes. Through a comparison of trace elements and hierarchical clustering analysis of rare earth elements, the suspected solid bitumen manifests the closest correlation with the mudstone source rocks of the Cambrian Zhangxia Formation. Early Devonian period, the Cambrian mudstone source rocks in the Tongcheng area were uplifted; then weathered, leached, and fragmented into powder; and then filled the fractures of the underlying Mesoproterozoic Jixian System. Of course, another geological scenario has not been ruled out: that some of the fractures in the Jixian System may be filled with solid bitumen, which may be the result of the destroyed paleo-oil reservoirs near the ancient uplift in the Tongcheng area. Full article

Carbon capture and storage (CCS) represents a critical technology for achieving climate neutrality targets, particularly for regions with significant industrial CO₂ emissions. This study presents a comprehensive numerical simulation assessment of CO₂ geological storage potential in the Sarmatian formations of the Getic Platform, Romania, located near the Turceni power plant—one of Europe’s largest thermal power facilities. Using ECLIPSE 300 compositional simulator with the CO2STORE option, we developed reservoir dynamic models incorporating geological properties, fluid characteristics, and pressure–volume–temperature (PVT) data specific to the Sarmatian aquifer system. Multiple injection scenarios were evaluated, including configurations with 3, 4, and 5 injection wells at varying inter-well distances (2000–10,000 m). The simulations covered a 20-year injection period followed by 300 years of monitoring. While previous assessments have provided static capacity estimates for Sarmatian formations, this study presents the first dynamic simulation-based evaluation of multi-well injection scenarios and long-term CO₂ trapping behavior in this geological setting, directly linked to the Turceni Power Plant emissions profile. Results demonstrate that the study area (Zone V) can accommodate the target CO₂ injection rate of 2.07 × 10⁶ Sm³/day using five injection wells, with final reservoir pressure increasing only 7–9 bar above initial conditions, well below fracture pressure thresholds (~280 bar). Long-term simulations reveal favorable CO₂ trapping behavior, with significant portions immobilized through residual and dissolution trapping mechanisms. The static storage capacity was estimated at 2.44 × 10¹⁴ kg CO₂. These findings support the technical feasibility of large-scale CO₂ storage in Romanian Sarmatian formations, providing quantitative evidence for CCS implementation strategies in the region. Full article