The Hetao Basin is a Meso-Cenozoic depression-fault superimposed basin. For a long time, there were no seismic survey lines and little understanding of tectonic evolution, source rock development and hydrocarbon accumulation controlling factors, and accumulation laws. As a result, oil and gas exploration was limited and discoveries are few. In recent years, exploration ideas have changed. Fine structural interpretation from well-seismic combination and comprehensive evaluation on favorable plays based on field outcrop surveys and 2D infill seismic lines has led to new understandings of the tectonic evolution mechanisms. The Linhe depression has experienced four stages of tectonic evolution: an Early Cretaceous inversion and basin-forming stage, a Paleogene differential extension stage, a Neogene intensive extension fault stage, and a Quaternary strike-slip (or inversion) and reconstruction stage. It has also been determined that the Jilantai structural belt and the central fault belt are favorable areas for oil and gas exploration. There are three sets of source rocks in the Linhe depression: the 2nd member of the Guyang Formation (the Gu 2 member), the 1st member of the Guyang Formation (the Gu 1 member), and the Linhe Formation. Quantitative characterization of source rock distribution in different sedimentary periods has revealed the controlling laws of the three combined elements of “basin evolution - sedimentary environment - burial history”, with the central-northern area of the Linhe depression being identified as the predominant resource enrichment area. Comprehensive analysis of hydrocarbon accumulation conditions has established several new hydrocarbon accumulation models for inside and outside the source rocks. Based on this new understanding, metamorphic buried hill oil reservoirs and clastic fault-nose structural oil reservoirs have been discovered in the Jilantai structural belt in the central-southern Linhe depression, marking a major breakthrough in oil and gas exploration in the Archean buried hill and the Cretaceous system outside the source rocks. In the northern Linhe depression, a risk exploration well—Well Linhua 1X—was drilled, obtaining high flow rate of 305.76 m3/d in the Paleogene inside the source rocks. This represents another breakthrough in multi-belt and multi-layer exploration in the Linhe depression.

Both hydrocarbon reservoirs and sandstone-type uranium deposits occur in sedimentary basins. Comparison of the metallogenic and hydrocarbon accumulation conditions of the two will provide valuable reference for exploration work in sedimentary basins. This study discusses the similarities and differences in the processes of hydrocarbon accumulation and uranium mineralization in sedimentary basins based on analysis of field data and the accumulated experience of years of exploration for oil and uranium in the Qianjiadian sag. Discussions focus on the controlling factors affecting mineralization and hydrocarbon accumulation, such as source rocks, reservoir, migration and accumulation, and paleoclimate. The results show that the metallogenic conditions of sandstone-type uranium deposits and the hydrocarbon accumulation conditions of oil reservoirs are similar. They both need high-quality reservoirs, barrier layers, and good reservoir-barrier assemblages. However, there are great differences between them in material sources, migration patterns, and spatial distribution. Sandstone-type uranium deposits are typically exogenous and hydrodynamic migration deposits. Favorable metallogenic conditions occur in the transitional paleoclimatic environment of an arid-to-hot and humid climate, and deposits develop easily in shallow strata. Oil reservoirs, on the other hand, are typical authigenic deposits, which generally migrate and accumulate by buoyancy, are less affected by climatic factors, and are more easily preserved in deep strata. The radioactivity of uranium promotes the transformation of organic matter into hydrocarbons, while oil and gas generated in the early stage, escapes upward along faults and provides reducing agents and preservative agents for the mineralization of sandstone-type uranium deposits in upper strata. The discovery of supergiant sandstone-type uranium deposits in the Qianjiadian sag confirms that sandstone-type uranium deposits often coexist with oil and gas reservoirs in the same basin. By comparing their respective metallogenic and accumulation characteristics, it is concluded that the fault basins that developed and waned in the Late Mesozoic and Late Cenozoic are important locations for the coexistence of hydrocarbon and uranium accumulation in the same basin.

There are many relatively unexplored small-medium basins on the periphery of the Junggar Basin. Geological understanding of these basins is low, and geological data are sparse. Future risk exploration would benefit enormously from accurate analysis of the hydrocarbon source conditions in these basins and their oil and gas resource potential. This study describes the formations of main source rocks in the peripheral basins of the Junggar Basin and estimates the oil and gas resource potential of each basin. The study is based on seismic data, well logging, laboratory testing, and previous literatures. The method for basins with low levels of exploration is used for oil and gas resource assessment. The results show that Jurassic and Permian source rocks are the main oil source rocks in these basins. The organic matter abundance of the Jurassic coal-measure source rocks is high, with the rocks having reached the mature stage and having strong hydrocarbon generation capacity. The Permian source rocks are medium to good, the organic matter type is Ⅱ2-Ⅲ, and the source rocks are in the mature to high-mature stage. The Carboniferous and Devonian source rocks are the main gas source rocks. They are in the high- to over-mature stage and are gas-prone. Using the genetic method, the calculated total oil and gas resources of seven low-exploration basins on the periphery of the Junggar Basin are 15009.75×104 t and 339.27×108 m3, respectively, characterized as “more oil and less gas”. Based on this assessment, three favorable hydrocarbon accumulation models—for the Jurassic, the Carboniferous-Permian, and the Devonian—are established. The Heshituoluogai and Buerjin basins are identified as Type A basins with great oil and gas resource potential and considered to be the most promising areas for risk exploration.

The Dongsheng gas field, discovered in a tectonic transform zone in the northern margin of the Ordos Basin, is an important base for gas reserves and production increase in China in the near and medium term. Since the “13th Five Year Plan” period, understanding of the structural and sedimentary evolution characteristics of the Ordos Basin has been continuously deepened and the factors controlling source rocks, reservoirs, and migration conditions have been defined. Analysis has focused on regional structures and the differential configurations of hydrocarbon accumulation factors in the basin with the objective of developing new understandings and transforming exploration ideas. The enrichment laws of the various plays have been determined, effectively supporting an exploration breakthrough in the tight sandstones in the northern margin of the basin. This study shows that differential configuration of effective source rocks, reservoirs, and lateral transport channels is the main controlling factor for differential gas enrichment in the northern margin of the Ordos Basin. A successively developed paleo-uplift slope zone in the Duguijiahan gas play in the central Hangjinqi block has favorable gas accumulation conditions in the Lower Shihezi Formation, which can be described as “effective configuration of source rocks and reservoirs and sealing by up-dip pinch out”. Multi-stage fault activity provided effective transport channels for the formation of multi-layer gas reservoirs. The Duguijiahan play is the first choice for integrated evaluation for petroleum exploration and development and the exploration breakthrough in new strata. Recently, more than 100 billion cubic meters of proven gas reserves have been submitted in this area, effectively promoting development and productivity construction, improving the value of natural gas resources, and expanding the exploration area in the margin of the basin.

During the Paleogene, the Dongying Sag experienced multiple episodes of tectonic movement. This tectonic activity transformed the structural system in the sag, controlling its shape and the distribution of strata and sand bodies. This study analyses and describes the geological features of the sag before and after its structural transformation. In doing so it examines the fault styles and structural assemblage characteristics, stratigraphic framework and distribution laws, paleogeomorphology and subsidence center change, and the characteristics of the fault system. The results show that: (1) In the Paleogene, the Dongying Sag experienced a structural transformation from extension to strike slip-extension. The bottom horizon of the upper fourth member of the Shahejie Formation (T7x) is an important interface of this structural transformation. (2) The structural transformation styles and genetic mechanisms of the strike-slip-extension stage in the study area are determined. The structural transformation styles are divided into four categories. (3) The controlling effect of the structural transformation is identified. In terms of the stratigraphic system, the structural transformation surfaces are the discontinuous surfaces of formations, which formed unconformity surfaces. Vertically, the structural configuration of the sag changed both before and after the structural transformation, and the subsidence center migrated. On the plane, the structural transfer zone was the sedimentary transition zone, which divided the sedimentary systems into segments.

Deep tight sandstone reservoirs in the Middle-Lower Jurassic in the Yiqikelike area, Kuqa depression in the Tarim Basin, are characterized by complex diagenesis, strong heterogeneity, and poor understandings of reservoir characteristics and genesis. This paper analyzes the diagenetic evolution stages of these reservoirs and the factors controlling their physical properties in detail, using analysis methods such as casting thin section, Scanning Electron Microscope (SEM), physical property analysis, X-ray diffraction, and CT scanning. The results of previous research are combined, including regional stratigraphic burial history, paleo-geothermal history, Ro evolution history, and sedimentary facies. The results show that: (1) The reservoirs in the Middle-Lower Jurassic are characterized by low compositional maturity, high content of plastic litho-clast, and medium textural maturity. (2) The burial depth of the reservoirs is mainly 4,0005,000 m. The reservoir spaces are dominated by secondary dissolution pores and fractures, with average porosity of 7.21% and average permeability of 9.15 mD, which represents a low porosity and low permeability reservoirs. However, some reservoirs have high permeability due to the development of tectonic fractures. (3) The diagenetic evolution of the reservoirs can be divided into two stages. The first stage occurred before the Neogene and had two prominent features. One was burial compaction during initial sedimentation, which led to porosity reduction. The other is dissolution by humic acid during long-term shallow burial, which led to porosity increment. The second stage occurred after the Neogene. Diagenesis in this stage also had two particular features. One was lateral compaction of reservoirs during rapid burial, which led to porosity reduction. The other was cementation by large amounts of illite, generated at the same time, which also decreased porosity. Permeability of the reservoirs was improved by the development of large numbers of fractures. (4) The main factors controlling the physical properties of high-quality reservoirs are the hydrodynamic conditions during sedimentation, late diagenesis, and the tectonic compression. Sandstones developed in the sedimentary microfacies of coarse sand-braided river channels, and underwater distributary channels are rich in rigid grains such as quartz which have strong compression resistance, providing the sedimentary basis for the formation of high-quality reservoirs. The development of fractures has greatly improved reservoir permeability in the study area and is the main controlling factor for the development of high-quality reservoirs.

After more than 30 years of exploration in the Erlian Basin, it has become increasingly difficult to discover new sags and oil and gas reserves. In order to further expand the scope of exploration in the basin, the search for new sags has been extended in recent years to the Wenduermiao uplift in the southern margin of the basin, where it has been found that the Wulanhua sag has favorable petroleum geological conditions. Study of the petroleum geological characteristics and hydrocarbon accumulation conditions of the sag have determined that it has a duplex-fault structural pattern. It has experienced an early lake-basin-forming period, frequent episodes of volcanic activity, and strong late tectonic movements. Due to its unique geological conditions, various types of oil reservoirs have formed, such as clastic rock, andesite, and granite buried hill. The hydrocarbon accumulation and distribution laws have been determined, which can be stated as “hydrocarbon accumulation zone in the circum-sub-sag structure, multiple oil-bearing layers in the Paleozoic and Cretaceous, and oil and gas enrichment controlled by high-quality reservoirs”. A composite “multi-layer and multi-type” hydrocarbon accumulation model has been established in the Wulanhua sag, which now effectively guides oil and gas exploration in the sag. Recent drilling operations have discovered an oil and gas reserve replacement area with oil reserves of more than 50 million tons, representing another successful example of petroleum exploration in new areas in the Erlian Basin.

Study of the thermal evolution characteristics of source rocks in the Melut Basin in South Sudan is of great significance for oil and gas exploration in the basin. Following the restoration of thermal history of the Northern depression, the maturity history of source rocks in the Renk Formation was simulated using the “Easy% Ro” dynamic simulation method combined with the analysis of geological and geochemical data, and petroleum system modeling. Also, the hydrocarbon generation and expulsion history of the source rocks was studied by “Ro - hydrocarbon expulsion rate” model. The results show that there are some differences in the thermal evolution degrees of Renk Formation source rocks between the three sags in the Northern depression. The source rocks in the Jamous sag were the earliest to enter the mature, high mature, and over mature stages, followed by those in the Ruman sag. Source rocks in the Moleeta sag were the most recent. Due to these differences in thermal evolution history, there are also some differences in hydrocarbon generation and expulsion times between the three sags. Source rocks in the Jamous sag began to expel hydrocarbon in the late Cretaceous (88 Ma) and entered the large-scale hydrocarbon expulsion stage in the Paleocene. In the Ruman and Moleeta sags, large-scale hydrocarbon expulsion occurred in the Eocene. Overall, the hydrocarbon generation and expulsion times of source rocks in the Northern depression have a good matching relationship with the formation times of the traps and cap rocks of the Yabus/Samma Formation, Galhak Formation, and Gayger Formation. The main controlling factor for hydrocarbon accumulation in the Yabus/Samma Formation is oil-source connecting faults, while in the Gayger and Galhak Formations it is reservoir physical properties. The source rocks in the Renk Formation, with a high degree of thermal evolution and continuously expelling hydrocarbon, provide a rich material basis for oil and gas charging into stratigraphic-lithologic reservoirs in the Northern depression. Therefore, stratigraphic-lithologic reservoirs should be an important replacement area for future exploration in the Northern depression and deserving of further research and exploration.

There are a number of technical issues that affect the process of drilling in the central deep buried hill zone in the Raoyang Sag, Jizhong Depression. These include the large formation dip angle, complex formation pressure system, poor drillability of deep formations, instability of sidewalls, and a steep geothermal gradient. Technical research has been carried out with the objectives of increasing drilling speeds, reducing drilling costs, and accelerating the exploration and development process. Supporting technologies for fast drilling have been developed based on non-standard wellbore configuration optimization, surface pre-displacement of wellheads, simple managed pressure drilling, customized PDC bit design, polyamine KCl drilling fluid systems, etc. Following on-site application in Well YT1, average rate of penetration (ROP) increased by 39.86% compared with adjacent wells, the complex drilling time was reduced from 5.4% to zero, and the well construction period was shortened by 44.19%—a significant enhancement of drilling speed.

Network fracturing is the practical implementation of the development mode of “fracture-controlled reserves” in shale gas wells. Natural fractures are an important factor affecting hydraulic fracture propagation and post-fracturing effects. In China and elsewhere numerical simulation is the normally adopted method for studying naturally occurring fractures. However, based on field practice and statistical data analysis, this paper uses the classification method to examine the influence of natural fractures with different characteristics on fracturing operations and post-fracturing effects and carries out field research and evaluation of improvements to reservoirs in which natural fractures are developed. The results show that: (1) For reservoirs with natural micro-fractures, problems such as difficulty of proppant adding, small stimulated reservoir volume, and poor simulation effect can be addressed by adopting “pad high-viscosity fracturing fluid + low-viscosity slick water carrying proppants”. (2) For reservoirs with large-scale natural fractures, the complexity of fractures following artificial fracturing is low and the fracturing effect is not favorable. Large-scale natural fractures intersecting with wellbores at large angles are the geological factor that may be responsible for casing deformation and frac hit. There are some uncertainties regarding the effects of temporary plugging diversion fracturing processes on fracture propagation interaction and improvements in stimulation effects. (3) Follow-up research should focus on improvement of fracturing effects when large-scale natural fractures are parallel to the wellbore, as well as prevention of casing deformation and frac-hit when large-scale natural fractures intersect with wellbores.

The Cretaceous Bashijiqike Formation is the main producing layer of the Keshen gas field in the Kuqa piedmont. The deepest exploration well in the field is more than 8000 m. The reservoir pressure is 150 MPa, maximum temperature is 190 C, and the thickness is 100300 m. These extreme operating conditions and the attendant well-control risks limit the testing methods that can be used for evaluation of fracturing effects following stimulation. It is therefore necessary to develop a method for obtaining a clear understanding of whether this kind of reservoir is suitable for stimulation by volume fracturing and establish how to determine whether a reservoir has been effectively fractured. This study summarizes the network fracturing technologies commonly used for the ultra-deep reservoirs in the Kuqa piedmont. The geological and engineering factors that lead to the formation of complex fracture networks are analyzed. In doing so, interconnection and extension of artificial and natural fractures and the geological and mechanical conditions affecting the formation of longitudinal and transverse fracture networks are discussed. The theoretical change in operating curves that should result from successful temporary plugging diversion is studied. Actual operating curves and theoretical curves are then compared and analyzed after a temporary plugging diversion agent has been inserted in the artificial fractures. The conclusions are mutually verified by a combination of micro-seismic monitoring and interpretation of wells after network fracturing. The results show that, for ultra-deep and extremely-thick reservoirs with well-developed natural fractures, transverse fracture networks and longitudinal multi-layer stimulation can theoretically be achieved by fracturing. However, the temporary plugging diversion technologies currently used within fractures, and temporary plugging layering at the fracture opening, are ineffective. It is therefore important to engage in research on ultra-deep temporary plugging layering and temporary plugging diversion technologies that will provide strong technical support for efficient exploration of reservoirs deeper than 8000 m and increase the likelihood of exploration breakthroughs.

According to seismic exploration theory, a deployment plan for 2D seismic exploration in principle requires the in-lines to be perpendicular to the structure strike to better reflect structural features. Crosslines are generally required to be parallel to the structure strike, thereby forming grids with the in-lines in order to control the structural feature in two directions. Study of actual seismic data, related literature, and previous studies of the high-steep structural area in the Hetao Basin, has revealed marked differences between descriptions of geological bodies based on seismic data obtained from 2D seismic lines with different observation orientations. Surface survey data from lines perpendicular to structures show abrupt near-surface changes. On the actual stacked profiles, the shielding and scattering effects of high-steep structures lead to a decrease in seismic data quality. The results of this study suggest that seismic lines in high-steep structural areas need not necessarily be arranged in strict correlation to structure strike. Instead, deployment should be considered comprehensively based on the near-surface data and overall seismic geological conditions.

The oil reservoir in the Chang 8 member in the Huaqing area of the Ordos Basin is a typical low-porosity and low-permeability reservoir. It has poor physical properties, high content of interstitial materials, and a generally developed high-resistivity water layer. The coincidence rate of well logging interpretation is low, and identification of fluid properties is difficult. Causation analysis of the high-resistivity water layer indicates a high content of chlorite membrane in the study area. An asphaltene oil film is formed when asphaltene is adsorbed by the chlorite membrane, which blocks the pores, complicates the conductive path, and causes the phenomenon of “water in oil”. When combined with low-salinity formation water in the area, the resistivity of the water layers eventually becomes high. The well logging response of high-resistivity water layers is characterized by a high resistivity curve with a concave shape and high values for physical properties (permeability >1 mD, and porosity>15%). The well logging response of oil layers is characterized by a high resistivity curve with a convex shape and low values for physical properties (permeability <1 mD and porosity <15%). The petrophysical properties and formation mechanism of high-resistivity water layers can be determined from well logging response characteristics and identification methods such as a chart distinguishing curve morphology, a cross-plot of chlorite membrane content and resistivity, and correlation analysis of resistivity-porosity. These identification methods have solved the problem of high-resistivity water layer identification in the oil reservoir in the Chang 8 member, with the coincidence rate of well logging interpretation for each method increasing to more than 80%.

The ‘eccentric potential’ method is proposed as a measurement method for monitoring hydraulic fracture parameters under complex geomorphic conditions. A survey network is deployed in a flat area at a distance from the fracturing well, allowing interpretation of hydraulic fracture parameters such as fracture azimuth of coalbed methane wells by measuring the gradients of ground potential changes following the injection of high-salinity fracturing fluid and the low-potential abnormalities generated by rock fractures during the fracturing process. The method has been applied in on-site measurement of 28 wells in the Zhijin coalbed methane block of the Guizhou province and in the Pengshui shale gas block in the eastern part of the Sichuan Basin, with a success rate of 100%. In each case, the measured fracture azimuth (NNW-SSE) was consistent with the direction of the regional principal stress field. This provides an important basis for evaluating the effect of fracturing, obtaining operational parameters for fracturing, and formulating an overall development plan for these blocks.