The deep formations in petroliferous basins have become a practical field for petroleum exploration. Junggar Basin is characterized by long tectonic evolution history and complex geological settings. Based on the exploration achievements in recent years, the new exploration fields in deep formation have been predicted, which indicates that there are four new exploration fields in the deep to ultra-deep formations, including prototype marine basin oil and gas reservoirs, intra source rock unconventional oil and gas reservoirs in the Permian Fengcheng Formation in Western Depression, large-scale stratigraphic oil and gas reservoirs in hydrocarbon-rich sags, and Jurassic–Cretaceous structural oil and gas reservoirs in the southern marginal foreland thrust belt. For prototype basin oil and gas reservoirs, controlled by the scattered source rocks in multiple depo-centers in the Carboniferous, relatively independent whole petroleum system can be formed in these source kitchens. Intra source rock oil and gas reservoirs in the Permian Fengcheng Formation in Western Depression showed a hydrocarbon accumulation pattern of orderly distribution of conventional–unconventional resources. The deep formation in Pen 1 Well West–Shawan Sag is a practical field for discovering a large gas zone with resources of trillion cubic meters. In hydrocarbon-rich sags, jointly controlled by paleogeomorphology and lake level, large-scale stratigraphic traps were formed in deep formations, and the clustered oil and gas reservoirs in trough areas are favorable targets. The large-scale structural traps were formed in the Jurassic-Cretaceous in the southern marginal foreland thrust belt, and high-quality reservoirs can still be developed below 8000 m, possessing the geological conditions for forming large-scale gas reservoirs. The study shows that the petroleum exploration in Junggar Basin has entered a new stage focusing on deep formations, generally exhibiting the coexistence of conventional–unconventional oil and gas reservoirs in sequence. The high-quality source rocks and effective hydrocarbon accumulation factors provided a solid material basis and favorable conditions for deep oil and gas reservoirs in the basin.

Marine carbonate rocks in Tarim Basin are mainly distributed in the Early Paleozoic marine strata in cratonic zone, with a burial depth of greater than 6000 m, a large thickness, and wide distribution area. The reservoir formation and hydrocarbon accumulation mechanisms in ancient carbonate rocks are complex, so the case studies have important enlightenments for the petroleum exploration in the ultra-deep formation (≥6000 m). The arduous exploration of carbonate oil and gas resources in Tarim Basin for 40 years has been summarized, and the theory, technology and deployment ideas of major discoveries in large ultra-deep carbonate oil and gas fields have been analyzed. The field practice shows that the exploration of carbonate rocks in Tarim Basin has gone through four major stages. Through the understanding and innovation of geological theories of ultra-deep buried hill karst, reef beach karst, interlayer karst and fault controlled karst reservoirs, the formation mechanism of large-scale ultra-deep ancient carbonate rock karst reservoirs in paleo-uplift–slope–depression has been revealed, which has guided the transformation of exploration deployment ideas and major new breakthroughs; After implementing 3D high-precision seismic exploration, a series of exploration techniques dominated by quantitative fracture and cave carving and fine characterization of strike slip faults in ultra-deep carbonate reservoirs have been formed, achieving effective prediction of heterogeneous karst fractured and cavity reservoirs, and supporting the constant discoveries in ultra-deep complex carbonate rocks. The exploration theory and technical innovation of ultra-deep ancient carbonate karst reservoirs formed by exploration practice in Tarim Basin have broken through the traditional theories of “oil reservoir controlled by paleo uplift” and “dead line of oil generation” in the cratonic zone, and realized the major strategic shift from structural high part of the paleo uplift to the slope–depression zone. The experience of successful exploration in the ultra-deep ancient carbonate rocks includes the change of idea to bravely breaking the exploration forbidden zone and the integration of exploration and development.

In order to cope with challenges faced by Chinese oil enterprises in overseas risk exploration, including difficulties in acquiring high-quality assets and limitations in developing existing assets, and enhance international competitiveness, the risk exploration decision-making mechanisms of leading international oil companies are systematically analyzed. After collecting core data through expert interview and consulting research, six representative international oil companies, i.e., ExxonMobil, Eni, Shell, Equinor, TotalEenergies, and bp are optimally selected, and the decision-making management systems of three strategically balanced type enterprises, Equinor, Eni, and Shell are deeply analyzed. The study results indicate that international oil companies have established a four-stage standardized decision-making workflow (preliminary assessment and screening, in-depth study, implementation program, and operation), and three core mechanisms have been formed: (1) The full-process support has been achieved by professional team division system integrating “new venture team, exploration technical team, management team, and quality control team”; (2) The risks and returns are balanced by strategically-oriented portfolio optimization; (3) The technological collaborative innovation mechanism has been constructed, and the high-performance computing platforms and intelligent decision-making systems have been integrated to enhance decision-making efficiency. The typical case studies reveal that Equinor has shortened decision-making chains via regionally integrated organizational structures, Eni has achieved strategic goals through “dual exploration mode” and “multi-track parallel decision-making”, while Shell has optimally selected exploration targets using its play portfolio analysis framework. In terms of institutional characteristics of Chinese oil companies, a four-dimensional improvement roadmap is proposed, namely, strategic–asset portfolio synergetic optimization, standardized decision-process rebuilding, intelligent management platform development, and internal control system enhancement. These suggestions provide theoretical basis and practical reference for improving overseas oil and gas exploration decision-making and facilitating the transformation from scale-driven expansion to value-centric operation of Chinese oil companies.

The 10000-meter deep formation is an important field for intra source rock gas exploration in Kuqa Depression, which is a potential replacement field benefit from its large resource amount, good preservation conditions and near-source hydrocarbon charging. However, there is unclear understanding of structural traps, reservoir scale and oil and gas reservoir types. Based on geological study of deep structures, hydrocarbon generation potential evaluation, physical simulation of reservoir diagenesis and comprehensive analysis of hydrocarbon accumulation mode, the key conditions for gas accumulation in 10000-meter deep formations have been analyzed and favorable replacement fields have been optimally selected. The results show that, controlled by three detachment layers such as coal measure strata, huge thick mudstone, and Paleozoic unconformity, large fault anticlines, anticlines and fault block structures were developed in 10000-meter deep formations in Kuqa Depression, and mostly concentrated in Kelasu thrust belt. The huge thick Triassic–Lower Jurassic highly-over mature coal measures and lacustrine mudstone source rocks were developed in 10000-meter formations, with a hydrocarbon generation capacity of (1000–3000)×10⁸ m³/km². Jointly controlled by the large-area braided river delta plain–front huge thick sand bodies, rapidly deep burial in the late stage, ultra-high temperature and ultra-high pressure, and intense tectonic compressive stress, the large-scale fractured–porosity type reservoirs still have good physical properties at a depth of 10000 m, with a porosity of 5%–10% and a permeability of higher than 1 mD. The Triassic-Lower Jurassic regional near/intra source rock hydrocarbon accumulation combination was dominant in 10000-meter deep formation, generally forming structural-lithologic tight sandstone gas reservoirs. The Kelasu thrust belt is optimally selected as a strategic exploration zone, with an area of 4200 km², and gas resources of up to 1.5×10¹² m³, and the traps below Keshen Gas Field are favorable targets. The research results provide basic understanding for gas exploration in clastic rocks with a depth of 10000 meters in China, and lay geological theoretical foundation for further discovery of large gas fields below Kela–Keshen in Kuqa foreland basin thrust belt.

With the increasing maturity of petroleum exploration in petroliferous basins in China, it is necessary to expand strategic replacement fields for oil and gas industry development. Recent exploration breakthroughs reveal that the resource potential of intra-source tight gas exceeds 1×10¹² m³ in Sichuan Basin, emerging as a prospective new strategic replacement field. The fine core description, logging data interpretation, and geochemical analysis data of a large number of core samples have been integrated to analyze the genetic type and distribution characteristics of intra-source tight gas in Sichuan Basin, identify the hydrocarbon accumulation and enrichment laws, and clarify resource potential and future exploration orientations. The study results show that: (1) Influenced by multicyclic tectonic evolution and frequent sea–lake level fluctuations, multiple sets of high-quality thick source rocks were developed in Sichuan Basin, forming multi-type marine and continental intra-source tight gas reservoirs. (2) There are two types of source rock and reservoir assemblages of intra-source tight gas reservoirs. One is near-source gas accumulation, which is enveloped by source rocks, showing superior sealing conditions, such as tight gas in Qiongzhusi Formation and the fifth member of Xujiahe Formation; The other is source rock and reservoir integrated gas reservoir with high-pressure sealing conditions, such as marine marl tight gas in the second sub-member of the third member of Leikoupo Formation and the first member of Maokou Formation. (3) The estimated resources of the four sets of intra-source tight gas are more than 4×10¹² m³, including tight sandstone gas in Qiongzhusi Formation, tight marl gas in Leikoupo Formation, tight marl gas in the first member of Maokou Formation, and tight sandstone gas in the fifth member of Xujiahe Formation, showing major fields for further exploration, among which Ziyang–Penglai area is the most favorable area for Qiongzhusi Formation tight gas, the southern–central Sichuan Basin is the prospective area for marine marl tight gas, and Penglai–Jinhua area is a favorable exploration area for tight gas in the fifth member of Xujiahe Formation.

Field outcrops and drilling data reveal that the Paleozoic–Mesozoic coal rocks are widely distributed in Qaidam Basin, with certain hydrocarbon generation potential and good reservoir performance, which is a new exploration field in the basin. However, the level of research and understanding is relatively low. A systematic study on coal rocks in the Middle Jurassic Dameigou Formation and the Upper Carboniferous Keluke Formation in Qaidam Basin is conducted, including sedimentary environment, distribution, coal properties, reservoir characteristics, resource amount, and gas enrichment rules. In addition, gas resource potential in coal rocks is evaluated, and exploration deployment orientations are proposed in Qaidam Basin. The study results show that: (1) The limnic facies coal rocks in the Middle Jurassic have a single layer thickness of 2–30 m and a distribution area of 11100 km²; The transitional facies coal rocks in the Upper Carboniferous have a single layer thickness of 1–6 m and a distribution area of 5689 km². (2) The coal rocks in the Middle Jurassic and the Upper Carboniferous are semi-bright to bright coals in a middle coal rank stage, all possessing gas generation capacity; TOC of coal rocks in the Middle Jurassic Dameigou Formation is 32.22%–79.50%, with an average of 62.85%, and R_o is 0.77%–1.38%, with an average of 0.9%; TOC of coal rocks in the Upper Carboniferous Keluke Formation is 35.67%–98.34%, with an average of 72.40%, and R_o ranges in 0.92%–1.82%, with an average of 1.57%. (3) The coal rock reservoirs are characterized by good porosity and permeability properties, and the coal cleats have a high density, showing a reticular distribution pattern and good connectivity; The matrix pores such as stomata, mold pores, dissolution pores, intercrystal pores and plant tissue pores are observed; The measured porosity of coal rocks ranges from 5.26% to 34.01%, with an average of 15.65%; The permeability is 5.11–12.60 mD, with an average of 8.91 mD. (4) Five types of gas accumulation and dispersion combinations are classified vertically in coal rocks, among which the widely distributed coal rock–mudstone and coal rock–limestone gas accumulation combinations have good sealing conditions and high peak values of total hydrocarbon gas logging shows, indicating the most favorable combinations for coal rock gas enrichment. (5) The favorable areas of the Middle Jurassic in Yuandingshan–Jiulongshan area in the northern margin of Qaidam Basin and the Upper Carboniferous in Dulan–Wulan in Delingha area are optimally selected for further strategic exploration deployment. The above understanding is expected to guide the strategic deployment of coal rock gas in Qaidam Basin, pioneer new frontiers for coal rock gas exploration, and unveil a new chapter in natural gas exploration in the basin.

Over the past 50 years, breakthroughs have continuously been made in the exploration of the Jurassic system in Ordos Basin. Based on early discovered oil reservoirs and exploration and appraisal wells, drilling geological data, core analysis, and seismic data have been used to finely characterize the pre Jurassic paleogeomorphology, sand bodies, and structures in the basin and analyze characteristics of fault development in the 3D seismic area, identifying the types of Jurassic oil reservoirs in the study area and controlling factors, and pointing out further exploration orientations and potential of the Jurassic system in the basin. The study results show that: (1) The pre Jurassic paleogeomorphology presented a “U+V”-shaped multi-level ancient river structure, with nine types of small units such as inter-river hill and terrace, which significantly controlled oil reservoir types; (2) The Jurassic oil reservoirs were mainly generated by source rocks in the seventh member of the Triassic Yanchang Formation, and the episodic oil charging in the Late Jurassic–Early Cretaceous laid the foundation for the wide distribution area of oil reservoirs; (3) The coupling of ancient rivers and low-amplitude nose uplift structures controlled the distribution of oil reservoir clusters, and a stereoscopic hydrocarbon accumulation pattern was formed by a three-stage fault relay transport; (4) There is still huge resource potential with a level of 100 million tons in complex fault zones in the western basin margin and the northeastern part of Jingbian slope, as well as mature areas through fine exploration.

In Tabei area adjacent to Northern Depression and Kuqa Depression, the Upper Cambrian Lower Qiulitage Formation is characterized by dual hydrocarbon source supply and favorable geological conditions for hydrocarbon accumulation, showing significant exploration potential indicated by breakthroughs in Well Xiongtan 1. However, there is a lack of study on the fine sedimentary characteristics, microfacies distribution pattern, and deposition mode in the sequence framework, which restricts further exploration of Lower Qiulitage Formation. Through field stratigraphic survey of six sections (2334.4 m) in Xiaoerblak outcrop area, GR and carbon isotope curves measurement of two sections, and thin section observation of 555 core samples, the stratigraphy and sequence characteristics, sedimentary characteristics, and deposition modes of Lower Qiulitage Formation are systematically analyzed. The correlation of lithology, GR curve and carbon isotope curve clarifies that Lower Qiulitage Formation in the study area corresponds to SQ7 and SQ8 (absence of the top) in the platform–basin region. The main rock types include granular dolomite, clotted dolomite, stromatolitic dolomite and laminated dolomite. The restricted platform facies was dominant, which was subdivided into five subfacies and six microfacies, forming seven types of typical sedimentary sequences. Influenced by Wensu-Yaha paleo uplift, SQ7 is composed of tidal flat subfacies sediments with frequent cyclic changes of various microfacies and minor lateral variation, and a deposition mode of supratidal zone–intertidal zone–subtidal zone from paleo uplift to the basin has been established. During the deposition period of SQ8, the sedimentary subfacies transitioned from tidal flat to intra-platform beach subfacies, with significant lateral differences in the proportion of mound and beach bodies, and a deposition mode of intertidal zone–subtidal high-energy zone–intra-platform beach from paleo uplift to the basin has been established. A total of 61–74 sedimentary sequences are observed in SQ7 in the outcrop area, with high-quality reservoir–cap rock combination developed in a single sedimentary sequence, and the successive sedimentary sequences in the over-100-meter strata have the potential to form superimposed and connected lithologic oil and gas reservoirs. SQ8 is characterized by widely developed reservoirs and has the potential to form high-quality structural oil and gas reservoirs. Controlled by Wensu–Yaha paleo uplift, the mound beach facies reservoirs are widely distributed in the western Tabei area, with good physical properties. In areas with overlying tight lithology and faults connecting to source rocks, high-quality oil and gas reservoirs were easy to form, showing a favorable area for exploration. The research results provide orientations for further exploration of Lower Qiulitage Formation in Tabei area.

The deep to ultra-deep formations have abundant resources, which is currently a key field for petroleum exploration and research both domestically and internationally. The study on the maximum depth of oil and gas reservoirs has important practical significance for assessing deep oil and gas resources, deploying ultra-deep wells, and understanding exploration risks. Based on the theory of whole petroleum system (WPS), the method and process have been proposed to quantitatively predict the maximum depth of conventional, tight, and shale oil and gas reservoirs in petroliferous basins. Some cases of discovered oil and gas reservoirs and well drilling data have been studied to predict the maximum depth of oil and gas reservoirs in petroliferous basins such as Tarim, Junggar, Sichuan, Ordos, Songliao, and Bohai Bay in China. The study results show that the maximum depths of conventional, tight, and shale oil and gas reservoirs in the six major petroliferous basins are usually in the range of 800–4400 m, 5050–7990 m, and 5400–9300 m, which increase with decreasing geothermal gradient, better organic matter types, and higher oil wet property of the reservoir. With advancements in drilling technology and predictive capabilities, the scope of discovering oil and gas resources will continue to expand. In addition, the maximum depth of oil and gas reservoirs is influenced by tectonic movements in the context of in-situ geological conditions. Finally, based on the actual drilling results of shallow–medium–deep oil and gas in Tarim Basin, the predicted maximum depths of ultra-deep carbonate oil and gas reservoirs in the Cambrian–Ordovician exceed (9500±50) m
and (10500±100) m, respectively.

According to the “Technical Specification of Seismic Data Interpretation” (GB/T 33684-2017), oilfield companies use the accuracy of well–seismic depth errors as an important indicator for assessing the precision of seismic interpreted structure results. There are two problems during the implementation process. Firstly, the absolute error and relative error accuracies are artificially specified in the national standard, lacking certain theoretical basis and technical support, which has a low operability in actual practice; Secondly, oilfield companies have established corresponding enterprise standards, with the continuously higher accuracy requirements of well seismic–depth errors far exceeding the vertical seismic resolution. Based on the practice of oil and gas exploration in Sichuan Basin, four main controlling factors that affect well–seismic depth errors are deeply analyzed, including (1) migrated imaging methods; (2) velocity errors in variable-speed depth conversion; (3) horizon calibration; and (4) vertical resolution of seismic exploration. The absolute error of well–seismic depth is related to the magnitude of the longitudinal resolution wavelength λ in seismic exploration. Therefore, based on the wavelength theory of vertical resolution in seismic exploration, and targeted at various exploration stages (exploration, appraisal, development, and fine development) of oil fields, different fractional values of seismic wavelength (λ_n and K_λn) can be taken as important reference indicators for the absolute and relative errors of well–seismic depth, which is operable in practice and can be used as a reference for oil field managers to assess the accuracy of seismic interpreted structure results.

In Changqing Oilfield, tight oil production has a long history and a large scale, and it remains a key target for production capacity construction at present, accounting for 36.6% of the new production capacity. In response to the geological characteristics of tight oil reservoirs, and targeting at the goal of an optimal adaptation between well pattern and fracture network, the geology and engineering integrated research approach is applied to conduct fracturing optimization design using methods such as numerical simulation, big data analysis, and field test. As a result, the coiled tubing precise multi-stage fracturing technology for short horizontal wells has been developed, as well as key integrated technology of “optimization of fracturing timing, differential fracture design, precise fracture control, enhanced imbibition oil displacement, multi-stage fracture temporary plugging, and directional perforation”. This technical model has been applied in over 200 tight oil wells in Changqing Oilfield, significantly improving the degree of fracture control and oil production in horizontal wells. Microseismic monitoring results show that the degree of fracture control has increased from 60% to over 85%, the initial oil production of a 100-meter horizontal section has increased from 2.0 t/d to 3.4 t/d, and the single well production remains steady, with an oil production rate of 3.2 t/d in the year of reaching production capacity, showing satisfactory results as a whole. The key fracturing technology effectively supports high-efficiency development of tight oil in Ordos Basin and points out direction for further technical breakthroughs. The new insights provide references for large-scale and beneficial development of similar oilfields in China.

The reservoirs in HT1 well area in Hutubi area are characterized by relatively great burial depth, low porosity, low permeability and tight property. The fracture propagation law is unclear given the conditions of high temperature, high pressure and well-developed natural fractures, which poses challenges for fracturing construction. In order to solve this problem, triaxial compression tests have been conducted on core samples from the target layer under high temperature and high pressure conditions to obtain rock mechanic parameters such as elastic modulus and Poisson’s ratio. Based on geology and engineering integrated method, relevant lab test data, core observation, well logging and seismic interpretation data have been used to establish a 3D geomechanical model. Finally, constrained by the geomechanical model, the fracture propagation simulation, well construction parameter optimization design, production history fitting and prediction have been analyzed in vertical wells with natural fractures developed. The study results show that: (1) The average Young’s modulus is 37.5 GPa, and the average Poisson’s ratio is 0.25. The average maximum and minimum horizontal principal stresses are 220 MPa and 180 MPa, which are much higher than those of conventional gas reservoirs (generally less than 100 MPa). (2) By setting the length of 70 m and the interval of 150 m for small-scale natural fractures, the length of hydraulic fractures has been fitted using fracture parameter inversion method based on pump off pressure drop. (3) The simulation results indicate that the optimal construction parameters include a displacement of 8 m³/min, perforation interval of 8–10 m, liquid volume of 910 m³, and sand ratio of 10%–16%. (4) After fracturing and putting into operation, the duration of steady production extends by 8 years, and the cumulative gas production increases by 16.13×10⁸ m³, showing significant enhancement of fracturing results, which provides guidance for the development of similar blocks.