To achieve efficient development and clarify key controlling factors on gas recovery from the highly heterogeneous, ultra-high pressure, and thin reservoirs of the Middle Permian Qixia Formation in the Gaoshiti-Moxi block of Anyue gas field, central Sichuan Basin, the thin reservoirs (average thickness <10 m) of Qixia Formation in this area were evaluated for well productivity by integrating geologic and engineering factors, and the key controlling factors of well productivity were quantified. Results show that, (i) the reservoirs of Qixia Formation are mainly composed of grain shoal-dominated dolomite, and high-production wells are distributed in grain shoal plays with the shoal-formation ratio (SFR) ˃0.3; (ii) the higher the degree of dolomitization, the better the reservoir properties; the reservoir permeability can exceed 0.1 mD when the degree of dolomitization exceeds 60%; (iii) the presence of fracture improves the physical properties of shoal facies dolomite reservoirs, and high-production wells are realized within 1.0 km to the sides of faults; (iv) the well productivity is positively correlated with the high-quality reservoir thickness, and the vertical thickness of high-quality reservoirs for high-production wells is greater than 3 m; (v) the ultra-high pressure reservoirs exhibit the original gas in place (OGIP) of 42% higher and the absolute open flow potential (AOFP) of a gas well 2 times higher than normal-pressure reservoirs; (vi) the application of horizontal well with horizontal section length of 1 000-1 200 m helps to achieve optimal recovery from the reservoirs in the study area. It is concluded that the high gas recovery from the reservoirs in this area can be attributed to the following controlling factors: favorable sedimentary facies (a fundamental factor), degree of dolomitization (a critical factor), thickness of high-quality reservoir (an essential factor), fracture-enhanced dolomite reservoirs (a recovery assurance), ultra-high pressure retention (an energy carrier), and application of horizontal well (a technical guarantee).
To clarify the sedimentary characteristics and evolution patterns of the transition zone from open platforms to tidal flats in the middle segment of the western margin of the Ordos Basin, the Mesoproterozoic Jixian System in the Suanzaozigou section of Tongxin County was selected for detailed study. It involved stratigraphic section measurement, systematic thin section microscopic observations, trace element analysis, stable carbon-oxygen isotopes determination, and comprehensive sedimentological investigation. The types of sedimentary microfacies and their vertical evolution characteristics in the study area were identified, and the combination patterns of different sedimentary microfacies were established. The results show that, (i) the rock types of the Jixian System include stromatolitic dolomite, granular dolomite (predominantly arenitic), crystalline dolomite, and siliceous dolomite; stromatolites exhibit mainly horizontal, mound-shaped and wavy morphologies, lacking large-scale columnar ones; (ii) there develops vertically stromatolite assemblages such as horizontal-mound-shaped, wavy-mound-shaped, and horizontal-wavy-mound-shaped, confirming that they were formed in intertidal to supratidal depositional environments under weak hydrodynamic conditions with high-frequency sea-level fluctuations; (iii) discrimination based on environmental proxies and carbon-oxygen isotopes suggests that the study area was characterized by weakly oxidizing, hot and arid paleoclimatic and paleo-oceanic environments; and (iv) vertical sequence analysis reveals the sedimentary microfacies dominated by supratidal zones, grain banks, and minor intertidal zones, indicating a transition from tidal flats intercalated with grain banks under weak hydrodynamics in the early stage to interlaminated grain banks and tidal flats with alternating strong and weak hydrodynamics during the middle-late stages. It is concluded that the sedimentary characteristics of the Jixian System in the Suanzaozigou section reflect the rapid facies changes and narrow facies belts of the Mesoproterozoic open platform to tidal flat transition zone in the western margin of the basin. The sedimentary evolution is primarily controlled by high-frequency sea-level fluctuations.
To accurately characterize the parameters (e.g. density, azimuth, and connectivity) of small- to medium-scale fractures in tight sandstone reservoirs in the Jianyang block, central Sichuan Basin, based on the Rüger theory of anisotropy and the OVT-domain wide-azimuth seismic data, the characteristics of fractures in the fourth member of the Upper Triassic Xujiahe Formation (Xu-4 Member) in this study area were investigated through integrating the azimuthal anisotropy attribute G inversion and the stochastic discrete fracture modeling. Specifically, fracture-induced azimuth-varying signals were extracted by azimuth/gather-based anisotropic gradient inversion, fracture density and orientation were quantified using the elliptic fitting algorithm, and a multi-scale fracture network model was built with the constraints of logging and seismic data. The following results are obtained. First, the results of azimuthal anisotropy attribute G inversion coincide with the logging-derived fracture density by 85%, and the predicted principal azimuths for four verification wells including Well YQ105 correspond to the error lower than 14°. Second, the fracture modeling indicates that 2,894 dominant fractures are developed in the study area, and the density of secondary fractures associated with the NE-trending fault zone is significantly higher than that of the gentle tectonic zone. Third, fracture density is linearly correlated with ellipticity, and the spatial coincidence between high-value zone and image logging interpretation results reaches 90%. Fourth, the Fisher distribution parameter in the stochastic discrete fracture modeling can effectively characterize the fracture orientation concentration, and the consistency with the rose diagram around the well is 93%. It is concluded that the proposed technology breaks through the limitations in traditional characterization of small- to medium-scale fractures based on post-stack attributes, and provides a quantitative prediction as a viable geological support to sweet spot identification and optimal well placement in tight gas reservoirs.
It is challenging to identify fractures outside wellbores in the tight sandstone reservoirs with ultra-low porosity and permeability in the upper submember of the second member of the Upper Triassic Xujiahe Formation (hereinafter referred to as T3x23) in the Hexingchang area of the Western Sichuan Depression of the Sichuan Basin. To address the challenge, and clarify the controlling mechanism of fractures on gas-well productivity in this area, electrical imaging identification charts for natural fractures were established by comparing genetic mechanisms, occurrences and image characteristics of natural versus induced fractures, based on core fracture observations, thin-section micro-fracture analyses, and electrical imaging log data. Moreover, the consistency between fracture strike and current in-situ stress direction, as well as the correlation between fracture parameters and open flow potential (OFP) of gas wells were investigated, thereby defining a workflow for identifying near-wellbore geological bodies using acoustic remote detection technology. The results are obtained in four aspects. (i) T3x23 in the study area is dominated by low-angle fractures (55.9%), followed by high-angle fractures (27.5%) and oblique fractures (16.6%). The latter two are mostly open, indicating good effectiveness. (ii) Well productivity is controlled by fracture strike. Fractures oriented near E-W and NW-SE align with the direction of current maximum principal stress, resulting in single-well OFP up to 52.95×10⁴ m³/d, whereas wells with N-S-strike fractures have productivity less than 5×10⁴ m³/d. Effective fracture density shows a positive correlation with the OFP. (iii) The acoustic remote detection technology for identifying fractures outside wellbores can accurately characterize the fractures within 40 m around the wellbore. It is concluded that the established geology-engineering integrated fracture-evaluation system effectively enables the identification of fractures outside wellbores, thereby facilitating the optimization of development planning for fault-fracture reservoirs. The zones with developed near E-W-strike fractures are the targets for horizontal well trajectory optimization in this area.
The conventional dual-mineral volume model is not accurate enough in calculating the mineral composition of complex carbonates in the Middle Permian Maokou Formation in the MX-PL area of the Sichuan Basin. To precisely quantify the mineral composition, using the training samples learned from conventional logging data together with mineral lithology scanning logging results, a Natural Gradient Boosting (NGBoost) model was constructed to predict the carbonate mineral contents, and coupled with the SHapley Additive exPlanations (SHAP) for analyzing the logging curves. A dual-driven technological system of “intelligent algorithm + feature attribution” was formed for complex lithology identification and quantitative mineral content evaluation. Research results are obtained as follows: (i) Through the optimization of ensemble learning model, the accuracy of lithology identification for the Maokou Formation has increased from 55% to over 85%; the predicted determination coefficients of compositions including calcite, dolomite and quartz achieve 0.91, 0.87 and 0.86, respectively, with the quantitative accuracy for quartz improving sevenfold. (ii) SHAP global attribution indicates that shear-wave slowness contributes most to quartz content prediction, whereas neutron porosity serves as the key factor of sensitive curve for calcite content prediction. (iii) The feature coupling effect suggests that shear-wave slowness and neutron porosity synergistically enhance the positive effect for calcite content prediction, and the positive correlation between compressional- and shear-wave slowness determines the calculation model of quartz content. (iv) NGBoost provides a confidence interval of 80% which covers 78% of measured values, with the mean square error (MSE) lower than 0.003, significantly superior to XGBoot and random forest (RF) algorithms. It is concluded that the SHAP-empowered NGBoost model provides an accurate and interpretable solution for quantitative evaluation of complex minerals, and reveals the coupling patterns of logging curves to guide the optimization of petrophysical models for similar reservoirs.
To systematically review the development sequence, technical characteristics and industry application status of unsteady-state permeability testing technology, literature analysis and technical comparison were employed to investigate the theoretical foundations, key breakthroughs and limitations of pressure pulse decay, pressure drawdown, and pressure oscillation methods. In addition, the optimization and promotion pathways of the technology were discussed based on China’s cases of technology introduction, localization progress and cross-domain expansion. The results show that, (i) the pressure pulse decay method addresses the difficulties in permeability testing of low-permeability samples by establishing a decay model of differential pressure between the upstream and downstream ends of core samples; (ii) the pressure drawdown method, utilizing real-time pressure data and automated control acquisition techniques, has become the mainstream technique for medium-to-high permeability overburden porosity-permeability combined measurement system, achieving full-range coverage for samples with permeabilities of 0.001-30 000 mD; (iii) the pressure oscillation method enables signal gain through periodic pressure variations, but its stringent requirements for inlet pressure control precision have hindered its large-scale application in oil and gas fields; and (iv) Chinese research institutions have developed distinctive techniques with “Chinese characteristics” through localized innovation, such as eliminating the requirement for regular sample shapes and pushing the lower testing limit to 10-7 mD. It is concluded that China’s technological innovation and practices in the field of unsteady-state permeability testing not only advance oil and gas exploration and development technologies, but also provide new insights for testing ultra-low permeability media in fields such as aerospace.
In recent years, significant breakthroughs have been made in the exploration and development of the bottom-water gas reservoir in the second member of the Upper Sinian Dengying Formation (hereinafter referred to as Deng 2 Member), Penglai gas field, Sichuan Basin. These advancements have provided an important support for increasing gas reserves and production in this area. The multi-scale fractures and the nonuniformly distributed lithologic interlayers developed in the Deng 2 Member gas reservoir complicate the water invasion mechanisms, making it difficult to predict the water invasion dynamics in the early stage of development. Taking the Deng 2 Member gas reservoir as the research object, the water invasion characteristics of bottom-water gas reservoirs with developed multi-scale fractures and interlayers were revealed through indoor physical simulation experiments and theoretical analysis, and the limit of the critical flow pressure difference of multi-scale fractures was quantified. A chart for evaluating the sealing capacity of interlayers was constructed for the first time, identifying the water invasion risks in the Deng 2 Member gas reservoir. The results show that, (i) in the reservoirs with small-scale fractures developed, the bottom-water invasion exhibits typical “controllable and treatable” characteristics, and controlling the production pressure difference can effectively suppress nonuniform water invasion; the critical flow pressure difference required for water invasion in small-scale fractures is five times that in large-scale fractures; (ii) large-scale fractures are characterized by “more severe water invasion hazards and greater challenges in water control”; the water breakthrough time is shortened by 1/9 and the recovery factor is reduced by 20% under the same pressure difference; additionally, the adjustable range of the critical pressure difference is limited, making water control development more challenging; and (iii) the sealing capacity of interlayers is jointly controlled by their physical properties, thickness and distribution characteristics; a quantitative evaluation chart for the sealing capacity of interlayers is constructed for the first time, which illustrates the vertical water-blocking effects of interlayers in different zones. It is concluded that the research results provide a beneficial guidance for the scientific and efficient development of bottom-water gas reservoirs in the Sichuan Basin.
In order to identify the provenance of the formation water in the Middle Jurassic Shaximiao Formation gas reservoir of the Zhongjiang gas field, located in the Western Sichuan Depression of the Sichuan Basin, and its implications for gas reservoir preservation conditions, 24 samples of formation water screened out from 34 wells were investigated systematically for their chemical characteristics, water types, typical chemical coefficients, Novk phase diagram, isotope testing and provenance by means of multiple analysis methods. The following results are obtained. (i) The formation water is of the CaCl2 type, with the total dissolved solids (TDS) ranging 6 942.0- 77 289.1 mg/L, and an average pH value of 6.7, indicating weak acidity. Among the conventional ions, Cl- is the most abundant. (ii) The characteristics of the typical chemical coefficients (metamorphic coefficient, salification coefficient, desulfurization coefficient, and cation exchange coefficient) suggest that the formation water exists in a well-sealed reducing environment, favorable for gas accumulation and preservation. (iii) The Novk phase diagram characteristics of formation water samples from different wells are very similar, pointing to a common provenance. The comparison with the Novk phase diagram corresponding to the standard section of the Sichuan Basin reveals that the formation water is sourced from the second to fourth members of the Upper Triassic Xujiahe Formation. (iv) The analysis on hydrogen-oxygen and strontium isotopes shows that the formation water is primarily composed of paleometeoric water modified by crust-derived rocks. It is concluded that the research results are helpful for deeply understanding the chemical characteristics and provenance of the formation water, as well as the preservation conditions and accumulation process in this gas reservoir, and provide a theoretical basis for related researches; the technical idea of multi-method combination applied in this study can offer a reference for further researching the chemical characteristics of formation water based on conventional water sample analysis.
The phenomenon of retrograde condensation is a major factor restricting the productivity release in the late stage of condensate gas reservoir development. Condensate gas reservoirs with different condensate contents present various seepage characteristics near the wellbore during retrograde condensation. In order to accurately assess the degree of reservoir damage caused by retrograde condensation, precisely analyze the change laws of productivity, and thus identify efficient measures for eliminating the condensate blockage in pore throats, indoor core depletion experiments were conducted. The gas-phase permeability damage ratio was introduced to quantitatively characterize the degree of reservoir damage in the situation of retrograde condensation at different condensate contents. In addition, an experiment was designed to analyze the relief degree of reservoir permeability damage of condensate gas reservoirs with various condensate contents by injecting nitrogen, CO2, methanol or dry gas. The following results are obtained. (i) Higher condensate content and lower gas-oil ratio lead to more severe reservoir damage. (ii) With the continuous depletion of core pressure, the permeability damage ratio gradually increases. The most severe damage occurs when the pressure reaches the point corresponding to the maximum retrograde condensation liquid volume. Then the damage gradually decreases with further pressure reduction. (iii) Higher condensate content and lower gas-oil ratio result in better permeability recovery through medium injection. CO2 injection demonstrates strong performance in restoring permeability across multiple types of condensate gas reservoirs. It is concluded that the research results provide a valuable reference for evaluating different types of condensate gas reservoirs and selecting methods to mitigate retrograde condensation damage.
In order to accurately assess the aquifer activity in heterogeneous edge-water gas reservoirs and its influence on development and production, seepage mathematical models for two typical water-invasion patterns were established based on oil-gas reservoir seepage mechanics theory. The charts for predicting the gas recovery factor at the time of formation water breakthrough (hereinafter referred to as water breakthrough) in gas reservoirs under various conditions were compiled by numerical solution method. In addition, a number of typical well blocks in the Sichuan Basin were selected for case analysis to verify the effectiveness of the prediction method. The following results are obtained. (i) During the development of heterogeneous edge-water gas reservoirs, formation water advances nonuniformly along the well-developed fracture channels. Permeability contrast and aquifer-to-reservoir pore-volume ratio significantly influence the gas recovery factor when water breakthrough occurs. (ii) The charts for predicting the gas recovery factor at the time of water breakthrough under different permeability contrasts and aquifer-to-reservoir pore-volume ratios can quantitatively characterize and dynamically predict the aquifer activity in gas reservoirs. (iii) The new method provides good case analysis results of the typical well blocks. The comparison of the predicted recovery factor at water breakthrough with the actual data shows an average relative error of less than 5%, indicting the great accuracy and effectiveness of the method. It is concluded that the newly established method for quantitatively predicting the aquifer activity in heterogeneous edge-water gas reservoirs is beneficial to early formulation of development control countermeasures, extending the economic production period and improving recovery factor of water-bearing gas reservoirs. This method is suitable for the gas reservoirs with formation water invading through simple and high-permeability channels, but not fully applicable to the water-bearing gas reservoirs with longitudinal high-conductivity fractures or complex fracture networks.
In order to address the issues of poor performance of foam drainage gas recovery (hereinafter referred to as foam drainage) and frequent liquid loading in multiple gas wells with long-carbon-chain condensate of the Dongsheng gas field in the Ordos Basin, laboratory evaluation experiments were conducted to analyze the main factors controlling the foam drainage effect, and gemini amphoteric oil-resistance foam drainage agent was developed and applied in 10 wells for testing. The following results are obtained. (i) The darker the color of condensate, the higher the content of long-carbon-chain (C10+) components, and the greater the influence on the foam drainage. Conventional foam drainage agents lose all foaming ability in black condensate. (ii) The main factors influencing the foam drainage in oil-bearing gas wells are the long-carbon-chain components and their content in the produced condensate. (iii) Based on the characteristics of condensate and formation water produced in the gas field, a mixed carbon chain of CH14 and CH18 (with molar ratio of 8.5:1.5) is selected as the main agent, supplemented with condensate emulsifier to improve the emulsifying capacity of foam drainage system and fluorocarbon surfactant to reduce foam surface tension, and thus a gemini amphoteric foam drainage agent resistant to long-carbon-chain condensate is developed. The laboratory evaluation experimental results suggest that this agent achieves the liquid-carrying rates >80% for various oil-bearing water samples. (iv) Field application tests on 10 wells show that this novel foam drainage agent achieves an effectiveness rate of 90%, with an average production increase of 20% per well. It is concluded that the novel agent effectively overcomes the poor gas recovery performance of conventional agents for wells with long-carbon-chain condensate, providing technical guarantee for stabilizing production of Dongsheng gas field. It can serve as a reference for improving the foam drainage process system of similar oil and gas wells.
During ultra-deep well drilling operations, the downhole high temperature and high pressure, coupled with the overlength and overloaded pipe string, make the string prone to longitudinal deformation under the combined influence of factors including its own weight and hydraulic circulation. The dominant factors controlling pipe string elongation vary under different operating conditions, resulting in significant errors in determining the key operation parameters such as on-site well depth verification, prearrangement of drill pipe delivery for liner operation, and stuck point calculation. To accurately calculate the pipe string elongation, a practical method is derived with consideration of gravity, buoyancy, weight on bit (WOB), inner-outer pipe pressure difference, and additional axial loads generated by hydraulic interception of downhole motors and bits. Unlike segmented calculation approaches, a finite difference method is adopted to improve the accuracy. The following results are obtained. (i) Under the conditions of calculation cases, elastic deformation and hydraulic factors have dominant influence during drilling and bottom-probing depth verification. The inner-outer pipe pressure difference and the additional axial force generated by hydraulic factors such as tool interception induce a change in pipe string elongation up to 2.5 m, which means their influences are great and shall not be neglected. (ii) The proposed calculation method, considering gravity, buoyancy, WOB, inner-outer pipe pressure difference, and the additional axial loads induced by hydraulic interception of tools, has been field-validated with an average error of only 0.526‱, meeting practical engineering requirements. The conclusion indicates that this calculation method can effectively supports depth verification, bottom hole assembly (BHA) optimization, and operation safety control of ultra-deep wells. It is recommended to integrate the temperature and pressure effect to further improve the adaptability of this method.
Well Cheng 6, located in the eastern slope of Dongdaohaizi Sag in the central depression of the Junggar Basin, is a key vertical exploration well with a designed depth of 6 990 m. In order to improve the success rate of ultra-deep well drilling in this block and address issues of wellbore stability and reservoir protection in the process of drilling complex sections, technical difficulties of drilling fluid were reviewed, and a strategy of “strong inhibition, strong plugging, stable rheology, optimal density” was formulated. Based on optimizing drilling fluid treating agents, a high-temperature-resistant and anti-collapse formate drilling fluid system was developed and verified through laboratory evaluation test and field application. The following results are obtained. (i) The laboratory evaluation test shows that this drilling fluid system performs well in temperature resistance, inhibition, plugging, settlement stability, clay contamination resistance, and reservoir protection. (ii) Applied to the third-spud section of Well Cheng 6, together with corresponding on-site maintenance and treatment processes, the developed drilling fluid system has achieved remarkable application results, ensuring the wellbore stability during drilling process, smooth tripping, and completion operations, meeting the engineering requirements for efficient drilling. (iii) In field applications, the drilling fluid system exhibits stable rheological properties and low viscosity and shear force. The rheological properties change minimally after encountering gas zones; the settlement stability is maintained even under high-density condition, with no sand depositing at the bottom hole. (iv) This drilling fluid system can effectively address issues of wellbore stability and reservoir protection. Well Cheng 6 shows good wellbore quality, with the average hole enlargement rate of 3.25% in the third-spud section. Electric logging reveals good oil-gas shows, and the daily gas production of 3.4×104 m3 is obtained during completion testing. (v) Well Cheng 6 has achieved optimal and fast drilling with an average ROP of 3.16 m/h. Meanwhile, the Triassic and Permian geological data have been acquired completely and accurately, providing a solid data base for the following exploration and development. It is concluded that the developed drilling fluid technology provides a technical guarantee for the hydrocarbon exploration and development in this block, and is of reference significance for the construction and implementation of ultra-deep well drilling fluid in other blocks.
