As an important replacement resource, shale oil is a major exploration field widely concerned at home and abroad. The long-term exploration and development practice enabled to make significant breakthrough and progress in the exploration, development and research of shale oil in the seventh member of Yanchang Formation (Chang 7 member) in Ordos Basin: (1) On the basis of exploration breakthrough in the interlayered type shale oil and discovery of the first integral one-billion-ton level Qingcheng Oilfield, the large-scale and benefit development has been achieved, and a million-ton level national shale oil development demonstration zone has been constructed. (2) In the exploration of the laminated type shale oil, four types of laminated type have been classified of the fine-grained sedimentary complex for the first time, i.e., sandy lamina, tuffaceous lamina, high TOC argillaceous lamina, and medium-low TOC argillaceous lamina. The combination of sandy lamina and medium-low TOC argillaceous lamina is the optimal “sweet spot” interval of the laminated shale oil by evaluating their development scale, reservoir performance, oil-bearing property, movability, and crude oil properties. For the sweet spot interval, new logging evaluation methods such as M-N cross plot are used to finely interpret the complex lithology, and the directional perforation and cross-layer stereoscopic fracturing technology enable to achieve the spatial communication of sweet spots around the wellbore in horizontal section, forming technologies for the effective identification, prediction of sweet spots and reconstruction of the laminated type shale oil, and achieving a major breakthrough in risk exploration, with the primarily submitted predicted shale oil reserves of 2.05×10⁸ t. (3) The laminar type shale oil is subdivided into two categories. The medium-high maturity organic shale can be developed by horizontal well, and relatively high TOC (4%-14%) and high S₁ content are key indicators for screening favorable sweet spots. While the medium-low maturity organic shale is the most favorable target for in-situ transformation research. The strategic breakthrough has been made in the exploration of continental shale oil in Chang 7 member in Ordos Basin, which is a milestone in China’s petroleum exploration and development history, but it still faces great challenges. For example, the large-scale and benefit development has been achieved of the interlayered type shale oil, but further research should be conducted on the prediction of sweet spots, production increase and efficiency improvement, and enhanced oil recovery. The laminated type shale oil is facing more challenges and greater difficulty in benefit utilization due to the completely different sedimentary settings, lithologic combination, reservoir space, and engineering quality from the interlayered type shale oil. Therefore, by focusing on the reserve quality and oil movability, hydrocarbon accumulation law should continuously be studied and the research on supporting technology should be strengthened. While for the laminar type shale oil with relative low level of exploration and understanding, the theoretical research and pilot test should steadily be promoted.

In order to guarantee the policy of national energy resources security and accelerate domestic oil and gas production, confronting growing complex exploration objects, innovation and advance in reservoir stimulation are the most significant drivers for discovering resources and increasing reserves. By comprehensively reviewing the development history of reservoir stimulation and analyzing technical challenges for exploration target characteristics of PetroChina Company Limited (PetroChina), main progress of reservoir stimulation is systematically summarized, including the optimized design of fracture-controlled stimulation to maximize the release of reserves, the increasing operational capability of fracturing equipment, more robust downhole tools, lower cost of fracturing fluid and improved personalization, and the obvious trend of proppant to low-cost and small mesh size. The supporting role of reservoir stimulation for exploration discovery is clarified. A comprehensive analysis of the key problems faced by hydraulic fracturing is conducted in four aspects: i.e., primary elements of fracturing, fracturing design optimization, field operation quality, and technology evolution. Specifically, the countermeasures in four aspects are proposed: (1) igniting innovation of basic research to provide theoretical support for the progress of fracturing technology; (2) promoting the quality of five primary elements to support the high-quality development of reservoir stimulation technology; (3) promoting the precise technical scheme to provide guidance for more efficient exploration and development of oil and gas; (4) increasing the efficiency of technical management to create a new mode of efficient treatment of engineering management.

A major breakthrough has been made in the Cambrian buried hill dolomite reservoir in Well Tuotan 1 in Wensu-Xiqiu area on the south slope of Kuqa Depression in Tarim Basin, which is of great significance to the exploration of multi-target buried hill on the hydrocarbon facing side on the south slope of Kuqa Depression. Due to the complex geological conditions, there is a lack of clear understanding on hydrocarbon enrichment law, and it is difficult to identify geological structures and characterize traps, which restrict the petroleum exploration in the buried hills in the study area. Based on the systematic analysis of structural features, stratigraphic distribution in buried hill, source rock-reservoir-cap rock assemblage, hydrocarbon transport system, and exploration practice, a new pattern of hydrocarbon accumulation in the buried hill has been established. The Paleozoic structure in Wensu-Xiqiu area is a back thrust structure controlled by the front thrust Shajingzi-Xiqiu Fault and recoil thrust Wushinan Fault, which is further complicated by two secondary back thrust faults F1 and F2, forming three rows of Paleozoic buried hill structures, with the stratigraphic age from old to new from the near fault to the far fault area in each row of structures. Among them, the Cambrian buried hill strata have the largest distribution range in a NEE direction. The buried hill reservoirs are mainly composed of dolomite of restricted platform granular beach facies, and the high-quality fractured-vuggy type dolomite reservoirs are contiguously distributed after reconstructed by multi stage tectonic activities and long-term exposure and erosion. The hydrocarbon accumulation assemblage of the buried hill oil and gas reservoirs is composed of dual hydrocarbon supply by mudstone source rocks in the Triassic Huangshanjie Formation and the Jurassic Chakmak Formation, fractured-vuggy type dolomite reservoir, and cap rock of the overlying Paleogene gypsum salt rock; The hydrocarbon accumulation is characterized by “distant hydrocarbon supply from Kuqa Depression, hydrocarbon transport by unconformity surface, and hydrocarbon enrichment in structures on the hydrocarbon facing side”, with the main hydrocarbon accumulation period in the late Himalayan (4-1Ma). The successful drilling of Well Tuotan 1 has confirmed the huge exploration potential of multi-row and multi-type buried hills in Wensu-Xiqiu area, with the re delineated buried hill trap area of 840km², and the discovered oil resources of about 2.0×10⁸t and natural gas resources of about 590×10⁸m³, which is expected to be a new strategic replacement area for increasing oil and gas reserves and production.

A set of saline lake facies shale was deposited in Ⅳ-Ⅵ oil group of the upper member of Lower Ganchaigou Formation (E₃²) in Yingxiongling Structural Belt in Qaidam Basin, with high carbonate mineral content and well-developed laminae, in which great progress was made in the shale oil exploration. Therefore, the in-depth research should urgently be conducted on the laminated texture, depositional mechanism, and favorable lithofacies combination. The experimental results of core description, thin section identification, scanning electron microscopy and X-ray diffraction analysis show that the shale laminated texture in the study area is divided into three types, i.e., water stratified type laminated texture (Type Ⅰ) , seasonal type laminated texture (Type Ⅱ) and flood surging type laminated texture (Type Ⅲ). Type I shale shows a typical laminated texture deposited in seasonal stratified water body in saline lake, accounting for 70% of the total laminae, which is composed of clayey laminae and calcite laminae, with a single lamina thickness of 0.1-0.5 mm. In summer and autumn, the water body was stratified, and the upper water body was favorable for microbial proliferation. While in winter and spring, the water body stratification disappeared, which was beneficial to the deposition and the preservation of organic matters. In addition, Type Ⅰ laminated texture was featured by a low deposition rate, which was beneficial to the enrichment of organic matters, with an average TOC of 1.33%. Type Ⅱ laminated texture accounts for 20% of the total laminae, which is composed of clayey lamina and silty lamina, with a single lamina thickness of 0.5-1 mm. The deposition of Type Ⅱ shale was related to the seasonal variation of terrestrial inputs, showing rapid deposition rate, with an average TOC of 0.47%; The proportion of Type Ⅲ laminated texture is 10%, which is composed of clayey lamina and silty lamina, with a single lamina thickness of 0.5-2 mm, micro-scouring surface and lens-shaped siltstone veins developed, and an average TOC of 0.27%, indicating certain hydrodynamic conditions related to gravity flow and lake flow rather than non-hydrostatic environment, as well as rapid deposition rate. The shale in the study area was mainly developed in semi-deep lake, with the single sedimentary cycle including mudstone→shale→argillaceous dolomite→dolomite from bottom to top, and occasional sand gravity flow deposits. For Type Ⅰ laminated texture, the shale deposition sequence was superimposed on dolomite, with the average porosity of dolomite of 9.8%, forming good source rock and reservoir assemblage in micro scale, which was beneficial for shale oil accumulation, showing the favorable lithofacies combination of shale oil in Ganchaigou area. Macroscopically, this set of shale has high TOC, good physical properties, and high content of brittle minerals, which is an ideal interval for shale oil exploration and development in Qaidam Basin. The hydrocarbon generation potential of Type Ⅱ and Ⅲ shales is poor, which have low contribution to hydrocarbon accumulation.

The gypsum-salt rocks are developed in the Middle Cambrian in Tarim basin, and their distribution and sealing capacity are of great significance for the petroleum exploration in deep formations. By using mud logging, wireline logging, seismic, and well test data, the distribution and sealing capacity of gypsum-salt rocks are analyzed. Furthermore, the quality of gypsum-salt cap rock is evaluated from the perspective of rock type (i.e., salt rock, gypsum rock, and gypsum-bearing rock), burial depth, and tectonic deformation intensity. The study results indicate that: (1) The sedimentary sequence of gypsum-salt rocks in the Middle Cambrian in Tarim Basin is composed of salt rock, gypsum rock, gypsum-bearing rock, dolomite, limestone and mudstone, which is mainly distributed in the central Tarim Basin, with a small distribution range of salt rocks only in the central part, a slightly larger distribution range of gypsum rocks, and a largest distribution range of gypsum-bearing rocks, showing the characteristics of bull-eyed deposition pattern; (2) The superior gypsum-salt cap rocks are developed in the central-western Northern Depression, most areas in the central-western Central Uplift, and the north slope in the western part of Southwestern Depression; The medium-quality gypsum-salt cap rocks are developed in local areas in the central part of Central Uplift and the northern part of northwest structural belt in the eastern Southwestern Depression; The poor gypsum-salt cap rocks are developed in the central Tabei Uplift and the southern part of northwest structural belt in the eastern Southwestern Depression.

The deep shale gas reservoir (3500-5000m) in the Silurian Longmaxi Formation in Luzhou block in Sichuan Basin is an important replacement field for shale gas development in China. However, the geomechanical properties of reservoir rock and variation in in-situ stress lead to difficulties in the development process, such as the long drilling cycle and large difference in gas rate of a single well. The geomechanical study enables to deepen the understanding of in-situ stress field in the block and provides basis for optimizing well location placement, drilling engineering and fracturing design of horizontal shale gas wells. The acoustic logging, diagnostic fracture injection testing (DFIT), imaging logging, and laboratory stress measurement data are combined to construct a high-precision geomechanical model in Petrel software, which supports to identify the reservoir geomechanical property in the study area, and the application of geomechanical study results in engineering is discussed. The results show that Young’s modulus gradually increases and Poisson’s ratio decreases with the increasing burial depth in Luzhou block. The shale reservoir in Longmaxi Formation is characterized by abnormally high pressure, with pore pressure gradient ranging in 16.7-21.7 kPa/m. The strike-slip type stress regime is dominant in Luzhou block, with an overlying rock pressure gradient of 25.5 kPa/m, a minimum horizontal principal stress gradient ranging in 18.8-24.5 kPa/m, and the average ratio of the maximum horizontal principal stress to the minimum horizontal principal stress of 1.165, and the reservoir horizontal principal stress increases with the increase of Young’s modulus and pore pressure. The geomechanical study results are used to guide the well location placement, optimization of drilling fluid density in drilling engineering, and optimization of fracturing stages and clusters and engineering parameters in fracturing design. For example, the drilling fluid density was optimized to 1.85 g/cm³ in Well Y65-X, achieving “one trip drilling” of the deviated-horizontal section and a 67% reduction in drilling cycle compared to adjacent wells; The fine fracturing stages and clusters and engineering parameters were optimized for Well Y2-X, and a gas flow rate of 50.69×10⁴ m³/d was tested. The study concludes that the high-precision geomechanical model and achievements enable to effectively improve the drilling operation efficiency and gas flow rate of a single well, and serve for the benefit development.

With the deepening of exploration and development in Bohai Oilfield, complex fault block structures, igneous rock areas and deep-ultra deep formations have gradually grown to be the main exploration targets, and the probability of lost circulation in the Paleogene-Neogene is increasing, which is the main geological risk in drilling that restricts the increase of reserves and production in Bohai Oilfield. Due to the insufficient understanding of geological laws and mechanics mechanism of fractured leakage in the Paleogene-Neogene in Bohai Sea area, there is a lack of effective technical support for the prevention and treatment of lost circulation. Therefore, based on the systematic summary of the main controlling factors and mechanisms of lost circulation, the comprehensive well drilling, geological, seismic and outcrop data are used, and well seismic integrated statistical analysis and geomechanical modeling methods are applied to identify the characteristics and mechanical mechanism of fracture leakage fault-fracture systems in the Paleogene-Neogene in Bohai Oilfield. The study results show: (1) The fractured leakage is closely related to Tanlu Fault Belt. The flower centers of negative flower-shape structure composed of intersections of “Y” shaped faults and multi-level “Y” shaped faults, “X” shaped composite faults on the plane and high angle faults are prone to leakage. The igneous rock areas with mutation in the formation occurrence and the interior of volcanic conduit have high risks of lost circulation; (2) In the interbedding of thick mudstone and thin sandstone, there is a high strain in the thick mudstone, and the stress is mostly concentrated in thin sandstone, generally with fractures well developed, so the risk of lost circulation is the highest; (3) Based on the finite element simulation of stress field, the distribution characteristics of stress field around the volcanic conduits are clarified, and it is determined that there is a high risk of lost circulation in areas in volcanic conduits and 100 m around combined with actual drilling data.

Breakthroughs have been made in the Permian tight conglomerate in Manan area in Junggar Basin. The systematic reservoir study is conducted by using various data of drilled wells to identify the main characteristics and favorable conditions for forming reservoir. The study results show that the reservoir is mainly composed of conglomerates of fan delta distributary channel facies, which shows a tight conglomerate reservoir with low-ultra low porosity and low-ultra low permeability, and medium textural maturity; The main composition of the gravel is tuff, with low compositional maturity, and the cements are dominated by laumontite and calcite; The pores mainly include intragranular dissolution pores of feldspar and dark minerals, as well as intergranular dissolution pores of zeolite and carbonate cements, and the fractures are relatively well developed, jointly forming an effective reservoir system; Two secondary pore zones are observed at intervals 3200-3840 m and 4200-5200 m, and both are located in the abnormal high pressure zone. The diagenesis, fractures and abnormal high pressure are favorable conditions for forming effective tight conglomerate reservoir in the Permian.

There are abundant oil and gas resources in carbonate rocks in Zagros Basin, but the genesis of H₂S is complex. The petrology, homogenization temperature of fluid inclusions and isotopes are analyzed to identify the genesis and distribution law of H₂S. The study results show that gypsum, anhydrite and barite are well developed in the Cretaceous and Cenozoic, H₂S contents (<5%) are low and sulfur isotopic fractionation is large between H₂S and anhydrite, which indicate a high degree of bacterial sulfate reduction (BSR). In addition, thermal degradation of organic kerogen occurred in part of the Cretaceous reservoir, leading to the increase of H₂S content to a certain extent. The sulfate minerals are well developed in the Jurassic-Permian reservoirs with a great burial depth, and hydrocarbon inclusions are observed in calcite cements. H₂S contents are high (up to 40%) and the sulfur isotopic fractionation is large between H₂S and sulfate. Affected by the mixture of organic matter such as hydrocarbons, the carbon isotope of calcite shows a distinctly negative drift (-10‰). These suggest that thermochemical sulfate reduction was dominant. Multiple genetic types led to differences in H₂S contents in various blocks.

In seismic exploration in the piedmont zone, stacking velocity is generally used for variable velocity mapping. However, there is few study on the influence of the near surface conglomerate on the stacking velocity of the underlying strata, and there is a lack of effective methods for stacking velocity correction. The wedge-shaped model is applied to simulate the near surface conglomerates, and the characteristics of seismic wave travel time-incident angle curves at various locations are analyzed. In addition, by taking YKB area in Kuqa piedmont zone as an example, seismic forward modeling is conducted to verify the results, which confirm that an abnormally high stacking velocity is formed below the pinch out points caused by the near surface high-speed conglomerate, resulting in a lateral velocity variation of “low-high-low-high” from the inner-fan to the outer-fan. Based on this understanding, the stacking velocity is corrected by velocity trend line method, and the result map is compared with that by well velocity constraint method. The results show that the formation occurrence in the structural map obtained by the velocity trend line method is closer to the measured results, with a smaller depth error, which proves the effectiveness of this method in the near surface conglomerate development area in the piedmont zone with low level of exploration.

CO₂ foam fracturing is an effective measure to improve the development result of tight sandstone gas reservoir. The central part of Su X block in Sulige Gasfield is a major replacement area for stable gas production in the near future. Compared with the main production area in the northern part, it is characterized by poor reservoir continuity and physical properties, high saturation of movable water, leading to severe water lock damage of gas wells when using conventional water-based fracturing, and increasing difficulty in fracturing fluid flowback. By taking Well Su X-A3 as an example, the concept of geology and engineering integrated CO₂ foam fracturing is innovatively practiced.Firstly, the integration of geological modeling and numerical simulation is applied to analyze the production characteristic parameters such as reservoir physical properties, gas-bearing property and movable water distribution, so as to optimally select well location and perforation interval to avoid formation water damage; Secondly, the geology and fracturing integration is applied to analyze the matching between reservoir physical properties and fracturing technology, so as to optimize the fracturing fluid system, fracturing size and pumping program; Finally, by using the flowback, well test, and gas production data, the evaluation and correction integration is applied to assess the fracturing results and technological adaptability, correct the pre-fracturing geological model, and complete the closed loop of geology and engineering integration technology. The study results show that the application of the geology and engineering integration in the optimization design of CO₂ foam fracturing enables to more comprehensively and accurately understand the reservoir quality and production performance, improve the pertinence of CO₂ foam fracturing design, and provide guarantee for a better result by using CO₂ foam fracturing. Field practice shows that this method is more in line with the practical needs than the previous conventional water-based fracturing design.

At present, gas well snubbing operation is an important completion and workover technology in the global gas field development, which enables to avoid reservoir damage caused by conventional well killing operation, and has outstanding technical advantages such as reservoir protection, cost reduction and efficiency improvement. In view of the prominent technical problems such as short service life of annulus motive sealing wear-resistant parts in gas well snubbing operation, low pressure grade of inner pipe string sealing tools, and high risk of pipe string flying out and bending, research has been conducted on four aspects, including pressure control technology of annulus motive seal, pressure control technology of inner pipe string sealing, anti-pipe string flying out technology and anti-pressure bending technology. The motive sealing wear-resistant parts with a service life of over 1200m at the wellhead pressure of 35MPa have been developed, as well as the inner pipe string sealing tools at a pressure of 70MPa. The calculation formula of neutralization point and the calculation model of ultimate bending length of pipe strings have been established. The research results have successfully broken through technical bottlenecks such as annular motive sealing and inner pipe string sealing, and formed key technology of gas well snubbing operation, which have been applied for more than 1000 wells in PetroChina Changning-Weiyuan, Changqing Oilfield and Sinopec Fuling blocks, greatly improving the technical capability and efficiency of snubbing operation in gas wells, and obtaining significant results of production increase. The research shows that the key technology of gas well snubbing operation provides powerful technical support for conventional gas well workover and large-scale completion of shale gas wells.

Fracturing of vertical well and multi stage fracturing of horizontal well are the two main methods for developing tight oil/gas reservoirs, but few studies have focused on fracture parameter interpretation with non-uniform conductivity of multi-layer tight oil/gas reservoirs in multi-layer fracturing and commingling production wells. Therefore, the non-uniform conductivity of hydraulic fractures caused by differential fracture propagation during multi-layer fracturing is considered rather than the traditional scenario of uniform fracture conductivity of tight reservoirs. The well testing analysis model for non-uniform fracture conductivity of multi-layer tight oil/gas reservoirs in multi-layer fracturing well is established by using Laplace spatial transformation, Duhamel superposition principle and Stehfest numerical inversion method. In addition, the well testing type curve analyzing the flow regimes in multi-layer fractured well is researched and the influence of several factors on fluid flow laws is determined, including the wellbore storage capacity, fracture skin factor, fracture conductivity and reservoir properties. The results show that: (1) The fluid flow in multi-layer tight reservoir in multi-layer fracturing well is divided into five stages, in which the early flow regime is affected by wellbore storage capacity and fracture skin factor, and the mid-term flow regime is controlled by hydraulic fracture length and conductivity; (2) Given the same production pressure difference, the larger fracture length and higher fracture conductivity are beneficial to increase well production; (3) The pressure drop in hydraulic fracture zone will be underestimated and the early well production capacity will be overestimated if fracture conductivity and non-uniform fracture propagation are ignored. Finally, a case study of well testing interpretation is given and the hydraulic fracture parameters of each layer are obtained.