The existing fracturing technologies are not very adaptable to the deep shale gas development in the Luzhou block of southern Sichuan Basin, where the development of natural fractures is abnormal and the geological-engineering conditions are complex. To solve this problem, a 3D reservoir model was established to analyze the requirements for the geometric parameters of hydraulic fracture network with the goal of fully producing well-controlled reserves. Then, matrix model and natural fracture model were constructed based on the fine division of natural fracture patterns. Finally, the key fracturing parameters such as cluster number per stage, flow rate, and fracturing fluid intensity were optimized by using the hydraulic fracturing numerical simulation technology. The results show that the natural fractures in the Luzhou block are divided into two types (network fracture and unidirectional fracture), and the latter is subdivided into four patterns (high-angle fracture, low-angle fracture, parallel proximal fracture, and parallel distal fracture). The fracturing parameters for the two fracture types are optimized by using the numerical simulation. The results have been successfully applied to the test well on site, indicating that no downhole complexity occurred during the fracturing operation, and the estimated ultimate recovery (EUR) after fracturing is higher than the average of the well area. It is concluded that the optimized fracturing parameters for different natural fracture types effectively guide the optimization of fracturing plan for deep shale gas wells in the Luzhou block, and provide technical guarantee of fracturing parameter design for the development of deep shale gas in the study area and similar blocks.

Some petrological, geochemical and geophysical studies were conducted on the high-quality reservoirs of marine carbonate rocks as the main gas producers in Sichuan Basin and the common origin of each quality reservoir was discussed in an effort to broaden petroleum domains. Results show that (i) there exists an exclusive sedimentation named as rock fragmentation in these carbonate reservoirs, which the early diagenetic carbonate mud may be transported once more under poor concretion; (ii) controlled longitudinally by sedimentation cycles, this fragmentation has a certain periodicity and fundamentally extends into the mid-late highstand system tract of the cycles. While laterally by paleogeomorphology, especially syndepositional faults or slope break; (iii) this fragmentation mechanism stems from the difference of sedimentation rate among various depositional settings. When there is an obvious division between two kinds of adjacent setting, massive carbonate sediments at the higher position with larger calcareous space cannot accumulate in place. Being transported in low-lying zones towards the sea and following the principle of sedimentary differentiation, weakly consolidated carbonate rocks suffer from fracturing and collapse under the influence of paleogeography, gravity, and hydropower; and (iv) the quality reservoirs are closely related to fragments. The fragmentation may alter the mud’s physical composition and generate numerous original intergranular pores and vugs to enlarge the fragments’ surface area. And some unstable mineral within the fragments are fully dissolved by undersaturated fluid in low-lying zones, further having much extension in reservoir space. And carbonate sediments change apparently in their physical properties under the effect of both fragmentation and submarine karstification. In conclusion, for the rock fragmentation, the mechanism to form the beach, reservoir and trap can make traditional theories more colorful. Being conducive to broadening exploration domains, this innovative model provides a new exploiting idea in low-energy facies belts, structural slope or low-lying areas in Sichuan Basin.

To clarify the sedimentary characteristics and hydrocarbon exploration significance of shallow-water delta in the first member of Middle Jurassic Shaximiao Formation (hereinafter referred to as Sha-1 Member) in the western-central Sichuan Basin, the sedimentary setting, sedimentary microfacies types, sand-body distribution patterns, and geophysical response features of Sha-1 Member were analyzed systematically, and a sedimentary model was established, using the core, logging and contiguous 3D seismic data. Research results are shown as follows: (i) During the sedimentation period of Sha-1 Member, the paleotopography was gentle, with shallow water body that rose and fell frequently, a large shallow-water delta was developed under the alternating humid-arid climates, contributing the subaqueous distributary channel sand bodies with the cumulative thicknesses ranging 15-40 m, the widths of 300-8 000 m, and the maximum extension up to 200 km. (ii) The subaqueous distributary channel sand bodies are distributed in a reticulate pattern, enclosed within interdistributary bay mudstones, possibly forming large-scale lithologic traps, and accounting for more than 50% of the front sedimentary area. In contrast, the reverse-graded river mouth bars are sporadically developed and small in scale (with individual layer thickness not exceeding 6 m). (iii) The seismic responses reveal the bright spot of “trough at the top and peak at the bottom” with medium to strong amplitude. Strong amplitude continuous reflection is observed along the channel, while the amplitude weakens to both sides of the channel in the transverse direction. High-resolution 3D seismic data are crucial for the fine characterization of sand bodies. (iv) The shallow-water delta front sand bodies of Sha-1 Member show good physical properties (with the porosity of 7%-13%, and the permeability of 0.01-1.00 mD), and form an efficient source-reservoir assemblage with the underlying source rocks of the Upper Triassic Xujiahe Formation, supporting the discovery of large-scale gas reservoirs such as the Tianfu Gasfield in the central Sichuan Basin (with proven reserves of 1 500×10⁸ m³). In conclusion, the shallow-water delta is the main contributor to the current increase in continental tight gas reserves in the Sichuan Basin; besides, its sedimentary model featuring wide channel, thick sand body and optimal configuration provides a reusable geological model and technical paradigm for hydrocarbon exploration of similar reservoirs in the Xujiahe Formation and the Middle Jurassic Lianggaoshan Formation within the basin.

The Middle Permian Maokou Formation has recently emerged as one of vital reservoirs for natural-gas exploitation in Longnvsi area. However, Maokou reservoirs are characterized by strong heterogeneity resulting in uncertain forming mechanisms, which may retard their efficient exploration and development. Thus, the depositional and petrological characteristics, and reservoir space and types were analyzed for this formation after core observation, thin-section identification, and logging-data analysis. Moreover, reservoir-forming mechanisms and the main geological process controlling reservoir evolution were discussed to create an evolution model. Results show that (i) Maokou reservoirs in the study area are dominantly developed with fine- to medium- crystalline dolomite in the lower part of the second member of Maokou Formation (Maokou 2 Member). Generally, unreal images of residual grain are visible in the dolomite. And such reservoirs belong to low porosity and ultra-low permeability ones; (ii) their space consists of intercrystalline pores, intercrystalline dissolution pores, needle-like pores, contiguous fractures and vugs, and fractures. And they can be classified into three types, such as fractured-vuggy, vuggy, and porous reservoirs, with the first two as the predominant; (iii) dolomite reservoirs are mostly extended into grain-beach bodies. And not only fragmental shoal but bioclastic beach facies belts exhibit remarkably higher porosity than that in inter-beach sea and platform-flat facies belts; and (iv) initial pores are stemmed from meteoric freshwater of penecontemporaneous dissolution. Dolomitization preserves reservoir space. Early hydrothermal fluid invasion along faults induces hydraulic fractures to generate saddle-shaped dolomite filling. Accordingly, the created model is in line with the fragmental shoal as the basis, the penecontemporaneous dissolution for forming reservoirs, the dolomitization for reservoir preservation, and the hydrothermal alteration for making reservoirs better. In conclusion, strong heterogeneity in these Maokou reservoirs is jointly conditioned by sedimentary facies belts and multiepisodic diagenesis, with the dissolution attributing to reservoir basis, the expanded space due to the alteration, and beach bodies’ structure and fault system as the major controls on the development of quality reservoirs.

Both hole collapse and complexities easily happen in shale gas drilling due to exclusive bedding structure in shale, further to bring about incomplete logging data, like density logs. Therefore, to accurately predict logs just serves as one way to improve the prediction accuracy for shale gas reservoirs especially in certain areas with complex well conditions or with poor logging quality. Adopted some quality training samples from logging data in appraisal wells in a shale gas block of Sichuan Basin, a bi-directional long short-term memory (Bi-LSTM) neutral network model based on attention mechanism (Attention+Bi-LSTM model), which the existing density logs were conducted as label samples for deep learning, was built and trained to complete logging data. Moreover, conventional logs of non-radioactive sources in well correlation with density logs were selected, and attention mechanisms were incorporated into the Attention+Bi-LSTM model to reinforce characteristic learning. Results show that the density data predicted from acoustic, natural gamma ray, gamma ray without uranium and resistivity logging, and uranium element content, have an average correlation coefficient with actual density up to 0.94, also an increase of 13.6% than before. It is concluded that, with better flexibility in logs prediction in shale gas blocks, the Attention+Bi-LSTM model can effectively complete logging data, reduce radioactive-source risks as needed, and save time and costs. This built method is worth popularizing.

Information technology is expected to be introduced into the efficient development of unconventional hydrocarbon resources, and the sharing and analysis of professional data in shale gas geology-engineering integrated researches. Therefore, an integrated shale gas geology-engineering data analysis platform (hereinafter referred to as the integrated platform) has been constructed by using the data cube model together with the Business Intelligence (BI) tool for data management. The research results show that, (i) a data collection area is established to serve as a data source, enabling the integrated platform to achieve the unified collection and storage of various professional data on shale gas; (ii) a data asset area is built to provide a professional data warehouse encompassing the exploration and development data model (EPDM) and the business wide table, which helps obtain high-quality data as the foundation for data cube construction; (iii) a series of data cubes that support multi-scenario applications are constructed to unify the indicator coverage, providing data support for scenario applications; (iv) a core indicator dashboard is designed to visually display various key indicators, by which several reusable data dashboard components and specific functional modules can be formed to provide support for scenario applications; and (v) professional application scenarios involving drilling, fracturing, flowback, and production performances, etc., are established to form business subject domains, thus creating a comprehensive research and production management system. It is concluded that the integrated platform can conveniently and visually display multi-dimensional data, rapidly respond to the user’s query requirement, and keep data closed while dimensional switching. The research findings provide not only a technical support to shale gas geology-engineering integrated studies but also a reference for construction of similar BI application platforms.

In order to address the challenges of limited drilling data, strong heterogeneity, and severe formation energy voidage in a low-permeability thin interbedded oil reservoir in the western South China Sea, and then to accurately predict the pressure during reverse pressure drive and fracturing operations in this reservoir, operation pressure prediction models were developed based on the Spearman correlation and grey relational analysis (GRA), together with linear regression and machine learning technologies. Firstly, geological reservoir and engineering parameters that significantly affect the pressure gradient of fracture extension were screened out through Spearman correlation and GRA. Secondly, based on the selected parameters, operation pressure prediction models were established by using linear regression and machine learning methods. Finally, these models were validated using the actual data from Well A1 in the reservoir. The results indicate that, (i) the methods of Spearman correlation and GRA can effectively identify key parameters affecting the pressure gradient of fracture extension; (ii) the prediction deviation rates of both linear regression and machine learning are within 10%, meeting the required engineering accuracy; (iii) when high-viscosity fracturing fluids are used, the prediction accuracy of machine learning is much superior to that of linear regression; and (iv) the predicted values of operation pressure in pressure drive and fracturing are highly consistent with the actual ones in Well A1, validating the reliability of the established models. The conclusion suggests that the operation pressure prediction method based on machine learning can provide an accurate guidance for reverse pressure drive and fracturing operations in the low-permeability thin interbedded reservoir in the western South China Sea. Additionally, it can serve as a reference for pressure prediction in similar reservoir stimulation operations.

Petroleum exploration success is commonly evaluated using each of indexes, for example reserve-discovered cost and proven geological reserves per well. Such evaluation pattern, however, is too simple, bringing about the evaluated index incapable of mirroring the internal composition in this success thoroughly and systematically, and the evaluated results failing to give objective response to practical benefits. It is hard to make measures in depth. Thus, dependent on some achievement data of recent years, the exploration success was quantitatively appraised through the created comprehensive evaluation model. Results show that (i) with the success as the soul, the preliminary index system covering four categories and nineteen sub-indexes is set up through sorting out principal indexes which may characterize the success at the whole exploration process; (ii) including four categories and thirteen sub-indexes, the core index system is also built by means of the principal component analysis (PCA) to screen indexes; (iii) the scoring coefficient is attained for each index by way of PCA. And taken the coefficient share as the weight, the comprehensive evaluation model is developed through the synthetical index method; and (iv) in accordance with the appraised success, the standard for success division is established by means of k-means cluster analysis. In conclusion, these established systems are rather reasonable and the evaluated results boast the quality of objectivity, which is conducive to the petroleum exploration success in continuous optimization.

As a new exploration and development domain of tight gas in Ordos Basin, Qingshimao gasfield is the first large one with the natural-gas reserves exceeding 100 billion cubic meters in Ningxia Hui Autonomous Region. Low gas production and high water-gas ratio emerged at the process of production test in this field, creating more challenges in beneficial development of tight-gas sandstone reservoirs. Thus, the eighth member of the Permian Lower Shihezi Formation (He 8 Member) was taken as an example to probe into physical properties and pore-throat microstructure in such reservoirs by means of porosity and permeability analysis, cast thin-section identification, and constant-rate mercury injection in order to figure out gas-water seepage laws and development mechanisms. Then, the initial water saturation was ascertained for these reservoirs on the basis of the sealed coring for pyrolysis weighing, routine coring or displacement and nuclear magnetic resonance. Additionally, both seepage laws and development mechanisms were made clear with the help of gas-water two-phase seepage experiments. Results show that (i) with low porosity and permeability, and medium to high water saturation, this member is generally tight gas reservoirs in which three types are developed, i.e., matrix porous type, fractured type, and matrix porous or underdeveloped fractured type; (ii) partial waterbody in some reservoirs whose characteristics are tight matrix, locally developed fractures and higher initial water saturation, is prone to non-uniform fingering along fractures. Hence, controlling water lock effect and avoiding water block damage are crucial to the beneficial development; and (iii) without cores, the criteria can be roughly established to identify produced fluids in the light of physical properties and gas content, providing geological evidence for selecting the best perforation interval and water control. In conclusion, all above results offer references for the selection of targeted zones and intervals for subsequent development in Qingshimao gasfield.

To break through the technical bottlenecks constraining China’s natural gas supply, this study systematically reviews the feasible application scenarios of large-scale artificial intelligence (AI) models in natural gas exploration and development. Taking DeepSeek as an example, an approach integrating technology transfer with case study is adopted, to construct a technology transfer pathway suitable for the natural gas sector by summarizing the paradigm of DeepSeek in industry applications. Furthermore, based on the practices of domestic oil and gas enterprises, the application scenarios of foundation models are thoroughly demonstrated. The following results are obtained. (i) In terms of knowledge management, foundation models can establish intelligent Q&A systems, internalize vast amounts of unstructured data, systematize expert experiences, and significantly enhance decision-support efficiency. (ii) Regarding data processing and interpretation, the multimodal fusion capability of foundation models enables the unified handling of multi-source data such as seismic and logging data, achieving intelligent extraction of geological features and accurate reservoir characterization to facilitate “sweet spot” prediction. (iii) For engineering operations, computer vision-based intelligent recognition technology for core thin sections allows for automatic and objective geological description. (iv) In production optimization, time-series forecasting and reinforcement learning models are leveraged to achieve real-time field-wide scheduling, fault warning, and operational optimization, thereby improving oil and gas recovery. (v) The deployment of large-scale AI models in natural gas exploration and development still faces challenges in respect to data security, domain-specific knowledge integration, model generalization, and system integration. In conclusion, exemplified by DeepSeek, large-scale AI models provide a key technological pathway for shifting the paradigm from “experience-driven” to “data- and model-driven”. In the future, by deepening domain knowledge embedding, exploring the synergy between large-scale and small-scale models, constructing human-machine collaborative platforms, and refining security frameworks, the intelligentization of natural gas exploration and development will be vigorously promoted, offering technical support for ensuring national energy security.

Working fluid invading into shale gas reservoirs may trigger hydration damage to shale under physical and chemical interactions during drilling and completion, further leading to fracture propagation and extension or even borehole instability, which may badly affect drilling safety and stimulation performance. Therefore, some experiments about hydration, ultrasonic transmission and nuclear magnetic resonance (NMR) were implemented on shale samples from the Lower Silurian Longmaxi Formation of Sichuan Basin in an effort to figure out hydration controls on shale’s pore structure and acoustic attributes. Variations in pore structure, acoustic velocity, and frequency-domain signals at different hydration times were discussed for these samples to reveal an intrinsic relation between the first two variations. Furthermore, dependent on elastic parameters, the quantitative characterization was established on the degree of hydration damage to shale. Results show that (i) in term of the pore structure throughout the hydration, small pores increase in their number, the size gets bigger successively, and large pores and microfractures emerge; (ii) with the increase of hydration time, the velocity decreases in a dramatic and then gentle manner. Low-frequency components evidently become lesser in frequency-domain signals after shale hydration; and (iii) the hydration damage accelerates and then slows down little by little, fast damage in the first six hours, sluggish in the following eighteen hours, and tending to be stable in the later twenty-four hours.

To understand the gas-water migration dynamic behaviors and the capacity variation laws of underground gas storage (UGS) converted from edge-bottom water gas reservoir during the multi-cycle injection and production process, the operation performance of the H UGS was analyzed and evaluated by using the numerical simulation technology, from the aspects of the variation of gas injection-production rate, the distribution characteristics of formation pressure, and the lateral and vertical variation of gas-water contact. The results are obtained in four aspects. First, in the process of multi-cycle injection and production, as the number of gas injectors and producers increases, the daily gas injection and production of the UGS increase steadily, and its peak-shaving and supply-guarantee capability gets enhanced year by year. Second, after multi-cycle injection and production, the formation pressure spreads gradually from structural high to structural low, and the pressure distribution tends to become more balanced. The gas injected into the UGS can be produced effectively as a whole. Third, the injection and production process of UGS is obviously different from gas reservoir development process. During the development process, gas-water migration is mainly unidirectional, with the gas-water front advancing into the interior of gas reservoir. Whereas in the process of UGS operation, multi-cycle injection and production are alternated, and the gas-water front advances outward from the UGS during injection but inward into the gas reservoir during production, i.e., moving forward and backward with the alteration of injection and production. Fourth, as the multiple-cycle injection and production goes on, the formation water is drained out of reservoir pores, and gas saturation increases correspondingly, which not only reduces the water invasion risk of the UGS in the production process compared with that in the development process, but also provides the UGS with the potential of continuous capacity expansion. The conclusion is that the gas-water migration dynamic behaviors and capacity variation laws of the UGSs converted form edge-bottom water gas reservoirs have a direct influence on their storage capacity and producing efficiency, and the research results are referential for the injection and production design and efficient operation of similar UGSs.

That some strategic breakthroughs in natural-gas exploration have been made recently in the Upper Sinian Dengying Formation, Moxi-Gaoshiti area, central Sichuan Basin, urges geologists to fix on deep, ancient, and organic-rich shale domain. To figure out both geochemical characteristics and sedimentary environment in source rocks of the Upper Sinian Doushantuo Formation will be momentous for deep to ultra-deep oil and gas exploration in the whole basin. Therefore, taken typical outcrop individually from Qingping town of Mianzhu city, Yangpingguan town of Ningqiang county, Xiaoyangba village of Zhenba county, and Gaoyan town of Chengkou county in northern basin as examples, such rocks were discussed from aspects of geochemical characteristics and redox conditions during source generation, as well as the effect of both paleoproductivity and hydrothermal activity on organic-matter accumulation by means of kerogen’s microscopic examination, trace-element analysis and elemental-ratio test. Additionally, an extension model was investigated for the source rocks of Doushantuo Formation. Results show that (i) these source rocks whose extension is conditioned by sedimentary facies are featured by the thickness ranging from 8 m to 493 m, the total organic carbon (TOC) content from 0.71% to 2.60%, and the carbon-isotope value between -25.5‰ and -36.2‰ in kerogen presenting some characteristics of sapropelic-humic hybrid; (ii) apparently influenced by tectonic-sedimentary differentiation, the rocks exhibit strong heterogeneity and great difference in planar extension. Among which, waterbody deposited in basinal facies is formed in anoxic setting with notable hydrothermal impact and the average TOC of 2.6%, indicating these source rocks in high quality; and (iii) the accumulated organic matter in Doushantuo Formation of northern basin is mainly controlled by redox conditions, and partially contributed to hydrothermal activity, but the paleoproductivity effect is ill-defined.

Based on the Al-Hussainy productivity equation in pseudo-pressure form, the critical pressure turning point of overpressured gas reservoirs was determined using the μZ-p and p/μZ-p plots, subsequently, the “one point method” productivity evaluation formula in pressure form for overpressured gas reservoirs was derived and established. Research results indicate that, (i) the pressure coefficients of typical overpressured gas reservoirs in China range from 1.34 to 2.29, and the initial formation pressures range from 49.28 to 150.00 MPa; (ii) based on the pressure-volume-temperature (PVT) parameters of 18 typical overpressured gas reservoirs at home and abroad, the critical pressure turning point of such reservoirs is determined to be 53.00 MPa; (iii) when the pressure of an overpressured gas reservoir exceeds 53.00 MPa, μZ and p are approximately linearly related, and p/μZ is approximately constant; in this case, the pressure binomial productivity equation should be used for solution; (iv) the established productivity evaluation formula is similar to the Chen Yuanqian’s “one point method” formula, with the distinction that the productivity equation coefficients and the absolute open flow (q_AOF) of gas well in the former are solved with the pressure binomial productivity equation; and (v) without the multi-point test, the stable empirical coefficient α' for gas well is unknown; if the average value of α' (i.e. 0.164 4) is utilized, there may exist an uncertainty. It is concluded that from the theoretical perspective, the proposed “one point method” formula in pressure form is more suitable for overpressured gas reservoirs. The application results show that the established productivity evaluation formula has an average error of 49.16% in calculating the q_AOF, which is lower as compared with the Chen Yuanqian’s “one point method” formula.

Deep shale gas reservoirs in the Upper Ordovician Wufeng - Lower Silurian Longmaxi Formations in the Yuxi block have great potential for further enhancing and stabilizing shale gas production of the southern Sichuan Basin. The H202 well area in this block has already entered the stage of large-scale productivity construction, but still faces challenges such as significant differences in the development effects of producing wells and unclear factors affecting productivity. To technically support the subsequent development of deep shale gas in the area, a geology-engineering integrated study was conducted on typical producing wells, by considering the factors including the distribution of Class I continuous reservoirs, targets, fracture characteristics and distribution, fracturing intensity, and proppant types. Based on summarizing the drainage gas recovery characteristics and production effects of producing wells, comparing and evaluating comprehensively the adaptability of development strategies, drilling techniques, and fracturing processes, the high-production well models in areas with fracture network were established, and the optimization measures were proposed for subsequent development of wells to be produced. The results indicate that, (i) static parameters of the reservoir are fundamental, and the areas with fracture network are selected for well placement by taking into account the basic characteristics including structure, sedimentation, reservoir, and fracture distribution; (ii) attention should be taken to ensure the penetration rate of high-quality reservoir and increase the drilling length of platinum target zone; (iii) operation parameters (displacement of 20 m³/min, fracturing fluid intensity of 40 m³/m, and proppant injection intensity of 4 t/m) should be improved in the areas with fracture network, so as to enhance the reservoir stimulation effects; and gradual prevention and control measures should be taken in the areas with unidirectional fractures, in order to especially ensure the wellbore integrity; and (iv) the proportion of ceramic proppant should be increased for both development effects and economic benefits. The research results provide a guidance for subsequent platform deployment and production, thereby facilitating the large-scale and beneficial development of deep shale gas.

Fractured-porous gas reservoirs with low resistivity are extended in the second member of the Upper Triassic Xujiahe Formation (Xujiahe 2 Member), Xinchang area, western Sichuan Basin. They are characterized by tight lithology, strong heterogeneity, and complex gas-water relation, resulting in considerable uncertainty in identifying reservoir-fluid properties by using conventional logs or popular gas-water crossplots. Thus, the (T₂-T₁) two-dimensional nuclear magnetic resonance (NMR) logging crossplot was created for identifying gas and water after optimizing both design and gauge on the basis of one-dimensional NMR logging. Moreover, the identification for this sort of reservoirs was discussed in the light of principles of apparent porosity frequency spectrum dependent on electrical imaging logging. Results show that (i) fluid components possess unlike zoning characteristics in the two-dimensional identification crossplot from which movable gas and water components in such reservoirs can be identified actively; (ii) with high resolution and coverage around wells, the imaging logging is available for not only pore structure analysis but gas-water identification in the low-resistivity fractured-porous reservoirs; and (iii) it is assumed the evaluated low-resistivity reservoir as a gas layer, but not as a gas-water layer. The gas-water identification interpreted from this new technology has higher coincidence with that of gas testing from previous 80% to current 95% or so.

Characteristically distinct flower reversal structures are widely observed in the structural zones in the western uplift and the III and IV secondary structural zones in the eastern reversal anticline of Doseo Basin, western Central Africa. However, these structures are indefinite in types, evolution process and relation with hydrocarbon accumulation. Based on drilling, logging and seismic data, a systematic study was conducted through analyzing equilibrium profiles, structures and hydrocarbon accumulation. Results show that (i) in the Early Cretaceous Neocomian-Barremian, the basin developed as an extensional rift, with its structural configuration and scale shaped initially; (ii) the III and IV secondary structural zones in the eastern reversal anticline are flower-shaped reversal structures controlled by strike-slip faults F₁ and F₂, and above them are the widespread development of an unconventional positive flower reversal structures. The prominent manifestation is that the upward divergent part of the flower shaped structure is mainly composed of small normal faults, but the geological morphology presents an antiform, while the western uplift structural belt develops large conventional positive flower reversal structures; (iii) the structural zones in the western uplift develop large-scale conventional positive flower reversal structures. The basin has evolved primarily in three stages: extensional rift, strike-slip, and depression. During the depression stage, it has also undergone three episodes of structural inversion. The evolution process of positive flower reversal structures are predominantly characterized by short rifting and long depression, strong extension-strike-slip, and three episodes of impulse reversion strong in the west and weak in the west; (iv) structural reversion activities controlled the development and distribution of positive flower reversal structures and associated traps; and (v) the traps of positive flower reversal structures at the III and IV secondary structural zones in the eastern reversal anticline are categorized into inner-source and above-source hydrocarbon accumulation models, and show good matches in terms of trap-formation time, peak hydrocarbon generation and expulsion of effective source rocks, episodes of structural reversion, and fault reactivation time.

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 the process of oil and gas well drilling in the Sichuan-Chongqing area, the presence of lost-return formations often result in unsuccessful plugging, even drilling accidents. To address the problem, a method for calculating two key parameters, namely the running depth of cementing tool and the sinking height of cement plug, was developed on the basis of the pressure balance principle. Additionally, the slurry design criteria were improved and the operation workflow was optimized, thus forming an integrated high-injection and high-squeeze cementing plug technology. Research results indicate that, (i) the density of plugging slurry is equal to that of drilling fluid, ensuring the slurry retention in wellbore as well as the success rate of cementing plug; (ii) the calculated running depth can not only quantitatively control the length of cement plug, but also ensure the safety of drilling tool; (iii) the adoption of bradenhead squeeze effectively directs the slurry flowing to the thief zone, increasing the success rate of plugging; (iv) staged squeezing the gelling cement into formation at the initial setting time effectively enhances the pressure-bearing capacity of formation; and (v) this technology has been applied in 33 wells, achieving the success rate of one-trip plugging of 90.9%, and statistical results of 7 wells show that the average pressure-bearing capacity per well is increased by 31.4%. In conclusion, the high-injection and high-squeeze cementing plug technology demonstrates remarkable effectiveness in sealing the lost-return formations in the Sichuan-Chongqing area, and can realize safe plugging while improving the formation pressure-bearing capacity in a single operation. It provides a technical guarantee for efficient drilling and safe production.

In order to reduce the failure rate of drilling tool in large-diameter boreholes in the Sichuan-Chongqing area, the service history of drill collar was reviewed with the failure accident of Ø228.6 mm drill collar while tripping out of the large-diameter borehole (Ø406.4 mm) of Well Z201-A as an example. In addition, the fracture-surface characteristics, drill string mechanical simulation and downhole vibration strength were analyzed. Accordingly, the causes of the failure were determined, and the drilling tool safety management measures were proposed. Research results are shown as follows: (i) The case drill collar failed due to fatigue, caused by weakened drill collar strength, complex loading on the drilling tool, and intense downhole vibration. (ii) After being used many times, the outer diameter of the drill collar is reduced from 228.6 mm to 226.0 mm, and the box-to-pin thread bending strength ratio (BSR) is 2.18, lower than the API standard value of 2.5. The weakening strength of box thread is one of the reasons for the failure. (iii) Mechanical simulations of the drill string reveal higher bending moments and stresses in large-diameter boreholes compared to small ones. The weak point of the bottom hole assembly (BHA) is adjacent to the centralizer, exhibiting the accelerated fatigue, which is the main reason for the failure. As the result, the broken drill collar is right above the centralizer. (iv) The surface strata where the large-diameter borehole (Ø660.4 mm) of the first spudding in Well Z201-A drilled into have alternate soft and hard lithologies. The wellhead torque measurements suggest intense downhole vibration with peak lateral vibration exceeding 30 g, which brings extreme damage to the thread. The downhole vibration calculation results indicate that the larger the borehole diameter, the greater the average equivalent stress of drilling tool, and for the borehole with diameter above Ø444.5 mm, the average equivalent stress increases exponentially. Compared with the weight on bit (WOB) fluctuation, the torque fluctuation has greater influence on the stress amplitude of drilling tool. (v) Based on the above findings, the specific measures for drilling tool safety management are proposed from two aspects, i.e., drilling technology and drilling tool management. It is concluded that the findings provide guidance for the safety of drilling tool in large-diameter boreholes, which is beneficial for reducing drilling tool accident rate, shortening drilling cycle, controlling costs, ensuring optimal and fast drilling, and improving quality and efficiency.