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Exploration and development of large gas fields is an important way for a country to rapidly develop its natural gas industry. From 1991 to 2020, China discovered 68 new large gas fields, boosting its annual gas output to 1 925×108 m3 in 2020, making it the fourth largest gas-producing country in the world. Based on 1696 molecular components and carbon isotopic composition data of alkane gas in 70 large gas fields in China, the characteristics of carbon isotopic composition of alkane gas in large gas fields in China were obtained. The lightest and average values of δ13C1, δ13C2, δ13C3 and δ13C4 become heavier with increasing carbon number, while the heaviest values of δ13C1, δ13C2, δ13C3 and δ13C4 become lighter with increasing carbon number. The δ13C1 values of large gas fields in China range from -71.2‰ to -11.4‰ (specifically, from -71.2‰ to -56.4‰ for bacterial gas, from -54.4‰ to -21.6‰ for oil-related gas, from -49.3‰ to -18.9‰ for coal-derived gas, and from -35.6‰ to -11.4‰ for abiogenic gas). Based on these data, the δ13C1 chart of large gas fields in China was plotted. Moreover, the δ13C1 values of natural gas in China range from -107.1‰ to -8.9‰, specifically, from -107.1‰ to -55.1‰ for bacterial gas, from -54.4‰ to -21.6‰ for oil-related gas, from -49.3‰ to -13.3‰ for coal-derived gas, and from -36.2‰ to -8.9‰ for abiogenic gas. Based on these data, the δ13C1 chart of natural gas in China was plotted.
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To explore the geological characteristics and exploration potential of the Carboniferous Benxi Formation coal rock gas in the Ordos Basin, this paper presents a systematic research on the coal rock distribution, coal rock reservoirs, coal rock quality, and coal rock gas features, resources and enrichment. Coal rock gas is a high-quality resource distinct from coalbed methane, and it has unique features in terms of burial depth, gas source, reservoir, gas content, and carbon isotopic composition. The Benxi Formation coal rocks cover an area of 16×104 km2, with thicknesses ranging from 2 m to 25 m, primarily consisting of bright and semi-bright coals with primitive structures and low volatile and ash contents, indicating a good coal quality. The medium-to-high rank coal rocks have the total organic carbon (TOC) content ranging from 33.49% to 86.11%, averaging 75.16%. They have a high degree of thermal evolution (Ro of 1.2%-2.8%), and a high gas-generating capacity. They also have high stable carbon isotopic values (δ13C1 of -37.6‰ to -16‰; δ13C2 of -21.7‰ to -14.3‰). Deep coal rocks develop matrix pores such as gas bubble pores, organic pores, and inorganic mineral pores, which, together with cleats and fractures, form good reservoir spaces. The coal rock reservoirs exhibit the porosity of 0.54%-10.67% (averaging 5.42%) and the permeability of (0.001-14.600)×10-3 μm2 (averaging 2.32×10-3 μm2). Vertically, there are five types of coal rock gas accumulation and dissipation combinations, among which the coal rock-mudstone gas accumulation combination and the coal rock-limestone gas accumulation combination are the most important, with good sealing conditions and high peak values of total hydrocarbon in gas logging. A model of coal rock gas accumulation has been constructed, which includes widespread distribution of medium-to-high rank coal rocks continually generating gas, matrix pores and cleats/fractures in coal rocks acting as large-scale reservoir spaces, tight cap rocks providing sealing, source-reservoir integration, and five types of efficient enrichment patterns (lateral pinchout complex, lenses, low-amplitude structures, nose-like structures, and lithologically self-sealing). According to the geological characteristics of coal rock gas, the Benxi Formation is divided into 8 plays, and the estimated coal rock gas resources with a buried depth of more than 2 000 m are more than 12.33×1012 m3. The above understandings guide the deployment of risk exploration. Two wells drilled accordingly obtained an industrial gas flow, driving the further deployment of exploratory and appraisal wells. Substantial breakthroughs have been achieved, with the possible reserves over a trillion cubic meters and the proved reserves over a hundred billion cubic meters, which is of great significance for the reserves increase and efficient development of natural gas in China.
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Based on the geochemical, seismic, logging and drilling data, the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin are systematically studied in terms of the geological characteristics, the tight oil enrichment model and its major controlling factors. First, the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation, with the development of nose structure around sag and the broad and continuous distribution of sand bodies. The reservoirs are tight on the whole. Second, the configuration of multiple elements, such as high-quality source rocks, reservoir rocks, fault, overpressure and structure, controls the tight oil enrichment in the Fuyu reservoirs. The source-reservoir combination controls the tight oil distribution pattern. The pressure difference between source and reservoir drives the charging of tight oil. The fault-sandbody transport system determines the migration and accumulation of oil and gas. The positive structure is the favorable place for tight oil enrichment, and the fault-horst zone is the key part of syncline area for tight oil exploration. Third, based on the source-reservoir relationship, transport mode, accumulation dynamics and other elements, three tight oil enrichment models are recognized in the Fuyu reservoirs: (1) vertical or lateral migration of hydrocarbon from source rocks to adjacent reservoir rocks, that is, driven by overpressure, hydrocarbon generated is migrated vertically or laterally to and accumulates in the adjacent reservoir rocks; (2) transport of hydrocarbon through faults between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downward through faults to the sandbodies that are separated from the source rocks; and (3) migration of hydrocarbon through faults and sandbodies between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks, and then migrates laterally through sandbodies. Fourth, the differences in oil source conditions, charging drive, fault distribution, sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs. Comprehensive analysis suggests that the Fuyu reservoir in the Qijia-Gulong Sag has good conditions for tight oil enrichment and has been less explored, and it is an important new zone for tight oil exploration in the future.
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Based on core and thin section data, the source rock samples from the Fengcheng Formation in the Mahu Sag of the Junggar Basin were analyzed in terms of zircon SIMS U-Pb geochronology, organic carbon isotopic composition, major and trace element contents, as well as petrology. Two zircon U-Pb ages of (306.0±5.2) Ma and (303.5±3.7) Ma were obtained from the first member of the Fengcheng Formation. Combined with carbon isotopic stratigraphy, it is inferred that the depositional age of the Fengcheng Formation is about 297-306 Ma, spanning the Carboniferous-Permian boundary and corresponding to the interglacial period between C4 and P1 glacial events. Multiple increases in Hg/TOC ratios and altered volcanic ash were found in the shale rocks of the Fengcheng Formation, indicating that multiple phases of volcanic activity occurred during its deposition. An interval with a high B/Ga ratio was found in the middle of the second member of the Fengcheng Formation, associated with the occurrence of evaporite minerals and reedmergnerite, indicating that the high salinity of the water mass was related to hydrothermal activity. Comprehensive analysis suggests that the warm and humid climate during the deposition of Fengcheng Formation is conducive to the growth of organic matter such as algae and bacteria in the lake, and accelerates the continental weathering, driving the input of nutrients. Volcanic activities supply a large amount of nutrients and stimulate primary productivity. The warm climate and high salinity are conducive to water stratification, leading to water anoxia that benefits organic matter preservation. The above factors interact and jointly control the enrichment of organic matter in the Fengcheng Formation of Mahu Sag.
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Based on the analysis of light hydrocarbon compositions of natural gas and regional comparison in combination with the chemical components and carbon isotopic compositions of methane, the indication of geochemical characteristics of light hydrocarbons on the migration features, dissolution and escape of natural gas from the Dongsheng gas field in the Ordos Basin is revealed, and the effect of migration on specific light hydrocarbon indexes is further discussed. The study indicates that, natural gas from the Lower Shihezi Formation (P1x) in the Dongsheng gas field displays higher iso-C5?7 contents than n-C5?7 contents, and the C6?7 light hydrocarbons are composed of paraffins with extremely low aromatic contents (<0.4%), whereas the C7 light hydrocarbons are dominated by methylcyclohexane, suggesting the characteristics of coal-derived gas with the influence by secondary alterations such as dissolution. The natural gas from the Dongsheng gas field has experienced free-phase migration from south to north and different degrees of dissolution after charging, and the gas in the Shiguhao area to the north of the Borjianghaizi fault has experienced apparent diffusion loss after accumulation. Long-distance migration in free phase results in the decrease of the relative contents of the methylcyclohexane in C7 light hydrocarbons and the toluene/n-heptane ratio, as well as the increase of the n-heptane/methylcyclohexane ratio and heptane values. The dissolution causes the increase of isoheptane values of the light hydrocarbons, whereas the diffusion loss of natural gas in the Shiguhao area results in the increase of n-C5?7 contents compared to the iso-C5?7 contents.
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Taking the Paleogene Shahejie Formation in Nanpu sag of Bohai Bay Basin as an example, this study comprehensively utilizes seismic, mud logging, well logging, physical property analysis and core thin section data to investigate the metamorphic reservoir formed by contact metamorphism after igneous rock intrusion. (1) A geological model of the igneous intrusion contact metamorphic system is proposed, which can be divided into five structural layers vertically: the intrusion, upper metamorphic aureole, lower metamorphic aureole, normal sedimentary layers on the roof and floor. (2) The intrusion is characterized by xenoliths indicating intrusive facies at the top, regular changes in rock texture and mineral crystallization from the center to the edge on a microscopic scale, and low-angle oblique penetrations of the intrusion through sedimentary strata on a macroscopic scale. The metamorphic aureole has characteristics such as sedimentary rocks as the host rock, typical palimpsest textures developed, various low-temperature thermal metamorphic minerals developed, and medium-low grade thermal metamorphic rocks as the lithology. (3) The reservoir in contact metamorphic aureole has two types of reservoir spaces: matrix pores and fractures. The matrix pores are secondary “intergranular pores” distributed around metamorphic minerals after thermal metamorphic transformation in metasandstones. The fractures are mainly structural fractures and intrusive compressive fractures in metamudstones. The reservoirs generally have three spatial distribution characteristics: layered, porphyritic and hydrocarbon impregnation along fracture. (4) The distribution of reservoirs in the metamorphic aureole is mainly controlled by the intensity of thermal baking. Furthermore, the distribution of favorable reservoirs is controlled by the coupling of favorable lithofacies and thermal contact metamorphism, intrusive compression and hydrothermal dissolution. The proposal and application of the geological model of the intrusion contact metamorphic system are expected to promote the discovery of exploration targets of contact metamorphic rock in Nanpu sag, and provide a reference for the study and exploration of deep contact metamorphic rock reservoirs in the Bohai Bay Basin.
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Based on the 3D seismic data and the analysis and test data of lithology, electricity, thin sections and chronology obtained from drilling of the Qiongdongnan Basin, the characteristics and the quantitative analysis of the source-sink system are studied of the third member of the Upper Oligocene Lingshui Formation (Ling 3 Member) in the southern fault step zone of the Baodao Sag. First, the YL10 denudation area of the Ling 3 Member mainly developed two fluvial systems in the east and west, resulting in the formation of two dominant sand transport channels and two delta lobes in southern Baodao Sag, which are generally large in the west and small in the east. The evolution of the delta has experienced four stages: initiation, prosperity, intermittence and rejuvenation. Second, the source-sink coupled quantitative calculation is performed depending on the parameters of the delta sand bodies, including development phases, distribution area, flattening thickness, area of different parent rocks, and sand-forming coefficient, showing that the study area has the material basis for the formation of large-scale reservoir. Third, the drilling reveals that the delta of the Ling 3 Member is dominated by fine sandstone, with total sandstone thickness of 109-138 m, maximum single-layer sandstone thickness of 15.5-30.0 m, and sand-to-strata ratio of 43.7%-73.0%, but the physical properties are different among the fault steps. Fourth, the large delta development model of the small source area in the step fault zone with multi-stage uplift is established. It suggests that the episodic uplift provides sufficient sediments, the fluvial system and watershed area control the scale of the sand body, the multi-step active fault steps dominate the sand body transport channel, and local fault troughs decide the lateral propulsion direction of the sand body. The delta of the Ling 3 Member is coupled with fault blocks to form diverse traps, which are critical exploration targets in southern Baodao Sag.
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The types, occurrence and composition of authigenic clay minerals in argillaceous limestone of sepiolite-bearing strata of the first member of the Middle Permian Maokou Formation (Mao-1 Member) in eastern Sichuan Basin were investigated through outcrop section measurement, core observation, thin section identification, argon ion polishing, X-ray diffraction, scanning electron microscope, energy spectrum analysis and laser ablation-inductively coupled plasma-mass spectrometry. The diagenetic evolution sequence of clay minerals was clarified, and the sedimentary-diagenetic evolution model of clay minerals was established. The results show that authigenic sepiolite minerals were precipitated in the Si4+ and Mg2+-rich cool aragonite sea and sepiolite-bearing strata were formed in the Mao-1 Member. During burial diagenesis, authigenic clay minerals undergo two possible evolution sequences. First, from the early diagenetic stage A to the middle diagenetic stage A1, the sepiolite kept stable in the shallow-buried environment lack of Al3+. It began to transform into stevensite in the middle diagenetic stage A2, and then evolved into disordered talc in the middle diagenetic stage B1 and finally into talc in the period from the middle diagenetic stage B2 to the late diagenetic stage. Thus, the primary diagenetic evolution sequence of authigenic clay minerals, i.e. sepiolite-stevensite-disordered talc-talc, was formed in the Mao-1 Member. Second, in the early diagenetic stage A, as Al3+ carried by the storm and upwelling currents was involved in the diagenetic process, trace of sepiolite started to evolve into smectite, and a part of smectite turned into chlorite. From the early diagenetic stage B to the middle diagenesis stage A1, a part of smectite evolved to illite/smectite mixed layer (I/S). The I/S evolved initially into illite from the middle diagenesis stage A2 to the middle diagenesis stage B2, and then totally into illite in the late diagenesis stage. Thus, the secondary diagenetic evolution sequence of authigenic clay minerals, i.e. sepiolite-smectite-chlorite/illite, was formed in the Mao-1 Member. The types and evolution of authigenic clay minerals in argillaceous limestone of sepiolite-bearing strata are significant for petroleum geology in two aspects. First, sepiolite can adsorb and accumulate a large amount of organic matters, thereby effectively improving the quality and hydrocarbon generation potential of the source rocks of the Mao-1 Member. Second, the evolution from sepiolite to talc is accompanied by the formation of numerous organic matter pores and clay shrinkage pores/fractures, as well as the releasing of the Mg2+-rich diagenetic fluid, which allows for the dolomitization of limestone within or around the sag. As a result, the new assemblages of self-generation and self-accumulation, and lower/side source and upper/lateral reservoir, are created in the Middle Permian, enhancing the hydrocarbon accumulation efficiency.
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Taking the Lower Cretaceous Qingshuihe Formation in the southern margin of Junggar Basin as an example, the influences of the burial process in a foreland basin on the diagenesis and the development of high-quality reservoirs of deep and ultra-deep clastic rocks were investigated using thin section, scanning electron microscope, electron probe, stable isotopic composition and fluid inclusion data. The Qingshuihe Formation went through four burial stages of slow shallow burial, tectonic uplift, progressive deep burial and rapid deep burial successively. The stages of slow shallow burial and tectonic uplift not only can alleviate the mechanical compaction of grains, but also can maintain an open diagenetic system in the reservoirs for a long time, which promotes the dissolution of soluble components by meteoric freshwater and inhibits the precipitation of dissolution products in the reservoirs. The late rapid deep burial process contributed to the development of fluid overpressure, which effectively inhibits the destruction of primary pores by compaction and cementation. The fluid overpressure promotes the development of microfractures in the reservoir, which enhances the dissolution effect of organic acids. Based on the quantitative reconstruction of porosity evolution history, it is found that the long-term slow shallow burial and tectonic uplift processes make the greatest contribution to the development of deep-ultra-deep high-quality clastic rock reservoirs, followed by the late rapid deep burial process, and the progressive deep burial process has little contribution.
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The ternary-element storage and flow concept for shale oil reservoirs in Jiyang Depression of Bohai Bay Basin, East China, was proposed based on the data of more than 10 000 m cores and the production of more than 60 horizontal wells. The synergy of three elements (storage, fracture and pressure) contributes to the enrichment and high production of shale oil in Jiyang Depression. The storage element controls the enrichment of shale oil; specifically, the presence of inorganic pores and fractures, as well as laminae of lime-mud rocks, in the saline lake basin, is conducive to the storage of shale oil, and the high hydrocarbon generating capacity and free hydrocarbon content are the material basis for high production. The fracture element controls the shale oil flow; specifically, natural fractures act as flow channels for shale oil to migrate and accumulate, and induced fractures communicate natural fractures to form complex fracture network, which is fundamental to high production. The pressure element controls the high and stable production of shale oil; specifically, the high formation pressure provides the drive force for the migration and accumulation of hydrocarbons, and fracturing stimulation significantly increases the elastic energy of rock and fluid, improves the imbibition replacement of oil in the pores/fractures, and reduces the stress sensitivity, guaranteeing the stable production of shale oil for a long time. Based on the ternary-element storage and flow concept, a 3D development technology was formed, with the core techniques of 3D well pattern optimization, 3D balanced fracturing, and full-cycle optimization of adjustment and control. This technology effectively guides the production and provides a support to the large-scale beneficial development of shale oil in Jiyang Depression.
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A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2 spectrum, and the time-varying law of simulated oil viscosity in porous media is quantitatively characterized by nuclear magnetic resonance (NMR) experiments of high multiple waterflooding. A new NMR wettability index formula is derived based on NMR relaxation theory to quantitatively characterize the time-varying law of rock wettability during waterflooding combined with high-multiple waterflooding experiment in sandstone cores. The remaining oil viscosity in the core is positively correlated with the displacing water multiple. The remaining oil viscosity increases rapidly when the displacing water multiple is low, and increases slowly when the displacing water multiple is high. The variation of remaining oil viscosity is related to the reservoir heterogeneity. The stronger the reservoir homogeneity, the higher the content of heavy components in the remaining oil and the higher the viscosity. The reservoir wettability changes after water injection: the oil-wet reservoir changes into water-wet reservoir, while the water-wet reservoir becomes more hydrophilic; the degree of change enhances with the increase of displacing water multiple. There is a high correlation between the time-varying oil viscosity and the time-varying wettability, and the change of oil viscosity cannot be ignored. The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott (spontaneous imbibition) wettability index, which agrees more with the time-varying law of reservoir wettability.
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A physical simulation method with a combination of dynamic displacement and imbibition was established by integrating nuclear magnetic resonance (NMR) and CT scanning. The microscopic production mechanism of tight/shale oil in pore throat by dynamic imbibition and the influencing factors on the development effect of dynamic imbibition were analyzed. The dynamic seepage process of fracking-soaking-backflow-production integration was simulated, which reveals the dynamic production characteristics at different development stages and their contribution to enhancing oil recovery (EOR). The seepage of tight/shale reservoirs can be divided into three stages: strong displacement and weak imbibition as oil produced rapidly by displacement from macropores and fractures, weak displacement and strong imbibition as oil produced slowly by reverse imbibition from small pores, and weak displacement and weak imbibition at dynamic equilibrium. The greater displacement pressure results in the higher displacement recovery and the lower imbibition recovery. However, if the displacement pressure is too high, the injected water is easy to break through the front and reduce the recovery degree. The higher the permeability, the greater the imbibition and displacement recovery, the shorter the time of imbibition balance, and the higher the final recovery. The fractures can effectively increase the imbibition contact area between matrix and water, reduce the oil-water seepage resistance, promote the oil-water displacement between matrix and fracture, and improve the oil displacement rate and recovery of the matrix. The soaking after fracturing is beneficial to the imbibition replacement and energy storage of the fluid; also, the effective use of the carrying of the backflow fluid and the displacement in the mining stage is the key to enhancing oil recovery.
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In order to clarify the influence of liquid sulfur deposition and adsorption to high-H2S gas reservoirs, three types of natural cores with typical carbonate pore structures were selected for high-temperature and high-pressure core displacement experiments. Fine quantitative characterization of the cores in three steady states (original, after sulfur injection, and after gas flooding) was carried out using the nuclear magnetic resonance (NMR) transverse relaxation time spectrum and imaging, X-ray computer tomography (CT) of full-diameter cores, basic physical property testing, and field emission scanning electron microscopy imaging. The loss of pore volume caused by sulfur deposition and adsorption mainly comes from the medium and large pores with sizes bigger than 1 000 μm. Liquid sulfur has a stronger adsorption and deposition ability in smaller pore spaces, and causes greater damage to reservoirs with poor original pore structures. The pore structure of the three types of carbonate reservoirs shows multiple fractal characteristics. The worse the pore structure, the greater the change of internal pore distribution caused by liquid sulfur deposition and adsorption, and the stronger the heterogeneity. Liquid sulfur deposition and adsorption change the pore size distribution, pore connectivity, and heterogeneity of the rock, which further changes the physical properties of the reservoir. After sulfur injection and gas flooding, the permeability of Type I reservoirs with good physical properties decreased by 16%, and that of Types II and III reservoirs with poor physical properties decreased by 90% or more, suggesting an extremely high damage. This indicates that the worse the initial physical properties, the greater the damage of liquid sulfur deposition and adsorption. Liquid sulfur is adsorbed and deposited in different types of pore space in the forms of flocculence, cobweb, or retinitis, causing different changes in the pore structure and physical property of the reservoir.
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For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid, the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture extension due to shale minerals erosion by oil-based drilling fluid. With the evaluation for the damage of natural and hydraulic fractures caused by mechanical properties weakening of shale fracture surface, fracture closure and rock powder blocking, the formation damage pattern is proposed with consideration of the compound effect of drilling fluid and fracturing fluid. The formation damage mechanism during drilling and completion process in shale reservoir is revealed, and the protection measures are raised. The drilling fluid can deeply invade into the shale formation through natural and induced fractures, erode shale minerals and weaken the mechanical properties of shale during the drilling process. In the process of hydraulic fracturing, the compound effect of drilling fluid and fracturing fluid further weakens the mechanical properties of shale, results in fracture closure and rock powder shedding, and thus induces stress-sensitive damage and solid blocking damage of natural/hydraulic fractures. The damage can yield significant conductivity decrease of fractures, and restrict the high and stable production of shale oil and gas wells. The measures of anti-collapse and anti-blocking to accelerate the drilling of reservoir section, forming chemical membrane to prevent the weakening of the mechanical properties of shale fracture surface, strengthening the plugging of shale fracture and reducing the invasion range of drilling fluid, optimizing fracturing fluid system to protect fracture conductivity are put forward for reservoir protection.
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Deep coal seams show low permeability, low elastic modulus, high Poisson's ratio, strong plasticity, high fracture initiation pressure, difficulty in fracture extension, and difficulty in proppants addition. We proposed the concept of large-scale stimulation by fracture network, balanced propagation and effective support of fracture network in fracturing design and developed the extreme massive hydraulic fracturing technique for deep coalbed methane (CBM) horizontal wells. This technique involves massive injection with high pumping rate + high-intensity proppant injection + perforation with equal apertures and limited flow + temporary plugging and diverting fractures + slick water with integrated variable viscosity + graded proppants with multiple sizes. The technique was applied in the pioneering test of a multi-stage fracturing horizontal well in deep CBM of Linxing Block, eastern margin of the Ordos Basin. The injection flow rate is 18 m3/min, proppant intensity is 2.1 m3/m, and fracturing fluid intensity is 16.5 m3/m. After fracturing, a complex fracture network was formed, with an average fracture length of 205 m. The stimulated reservoir volume was 1 987×104 m3, and the peak gas production rate reached 6.0×104 m3/d, which achieved efficient development of deep CBM.
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A three-dimensional reconstruction of rough fracture surfaces of hydraulically fractured rock outcrops is carried out by casting process, a large-scale experimental setup for visualizing rough fractures is built to perform proppant transport experiments. The typical characteristics of proppant transport and placement in rough fractures and its intrinsic mechanisms are investigated, and the influences of fracture inclination, fracture width and fracturing fluid viscosity on proppant transport and placement in rough fractures are analyzed. The results show that the rough fractures cause variations in the shape of the flow channel and the fluid flow pattern, resulting in the bridging buildup during proppant transport to form unfilled zone, the emergence of multiple complex flow patterns such as channeling, reverse flow and bypassing of sand-carrying fluid, and the influence on the stability of the sand dune. The proppant has a higher placement rate in inclined rough fractures, with a maximum increase of 22.16 percentage points in the experiments compared to vertical fractures, but exhibits poor stability of the sand dune. Reduced fracture width aggravates the bridging of proppant and induces higher pumping pressure. Increasing the viscosity of the fracturing fluid can weaken the proppant bridging phenomenon caused by the rough fractures.
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To address the issue of horizontal well production affected by the distribution of perforation density in the wellbore, a numerical model for simulating two-phase flow in a horizontal well is established under two perforation density distribution conditions (i.e. increasing the perforation density at inlet and outlet sections respectively). The simulation results are compared with experimental results to verify the reliability of the numerical simulation method. The behaviors of the total pressure drop, superficial velocity of air-water two-phase flow, void fraction, liquid film thickness, air production and liquid production that occur with various flow patterns are investigated under two perforation density distribution conditions based on the numerical model. The total pressure drop, superficial velocity of the mixture and void fraction increase with the air flow rate when the water flow rate is constant. The liquid film thickness decreases when the air flow rate increases. The liquid and air productions increase when the perforation density increases at the inlet section compared with increasing the perforation density at the outlet section of the perforated horizontal wellbore. It is noted that the air production increases with the air flow rate. Liquid production increases with the bubble flow and begins to decrease at the transition point of the slug-stratified flow, then increases through the stratified wave flow. The normalized liquid flux is higher when the perforation density increases at the inlet section, and increases with the radial air flow rate.
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In the mid-21st century, natural gas will enter its golden age, and the era of natural gas is arriving. This paper reviews the development stages of global natural gas industry and the enlightenment of American shale gas revolution, summarizes the development history and achievements of the natural gas industry in China, analyzes the status and challenges of natural gas in the green and low-carbon energy transition, and puts forward the natural gas industry development strategies under carbon neutral target in China. The natural gas industry in China has experienced three periods: start, growth, and leap forward. At present, China has become the fourth largest natural gas producer and third largest natural gas consumer in the world, and has made great achievements in natural gas exploration and development theory and technology, providing important support for the growth of production and reserves. China has set its goal of carbon neutrality to promote green and sustainable development, which brings opportunities and challenges for natural gas industry. Natural gas has significant low-carbon advantages, and gas-electric peak shaving boosts new energy development; the difficulty and cost of development are more prominent. For the national energy security and harmonious development between economy and ecology under the carbon neutral goal, based on the principle of “comprehensive planning, technological innovation, multi-energy complementarity, diversified integration, flexibility and efficiency, optimization and upgrading”, the construction of the production-supply- storage-marketing system has to be improved so as to boost the development of the natural gas industry. First, it is necessary to strengthen efforts in the exploration and development of natural gas, making projects and arrangement in key exploration and development areas, meanwhile, it is urgent to make breakthroughs in key science theories and technologies, so as to increase reserve and production. Second, it should promote green and innovative development of the natural gas by developing new techniques, expanding new fields and integrating with new energy. Third, there is a demand to realize transformation and upgrading of the supply and demand structure of natural gas by strengthening the layout of pipeline gas, liquefied natural gas and the construction of underground gas storage, establishing reserve system for improving abilities of emergency response and adjustment, raising the proportion of natural gas in the primary energy consumption and contributing to the transformation of energy consumption structure, realizing low-carbon resources utilization and clean energy consumption.
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Based on the methodology for petroleum systems and through the anatomy and geochemical study of typical helium-rich gas fields, the geological conditions, genesis mechanisms, and accumulation patterns of helium resources in natural gas are investigated. Helium differs greatly from other natural gas resources in generation, migration, and accumulation. Helium is generated due to the slow alpha decay of basement U-/Th-rich elements or released from the deep crust and mantle, and then migrates along the composite transport system to natural gas reservoirs, where it accumulates with a suitable carrier gas. Helium migration and transport are controlled by the transport system consisting of lithospheric faults, basement faults, sedimentary layer faults, and effective transport layers. Based on the analysis of the helium-gas-water phase equilibrium in underground fluids and the phase-potential coupling, three occurrence states, i.e. water-soluble phase, gas-soluble phase and free phase, in the process of helium migration and accumulation, and three migration modes of helium, i.e. mass flow, seepage, and diffusion, are proposed. The formation and enrichment of helium-rich gas reservoirs are controlled by three major factors, i.e. high-quality helium source, high-efficiency transport and suitable carrier, and conform to three accumulation mechanisms, i.e. exsolution and convergence, buoyancy-driven, and differential pressure displacement. The helium-rich gas reservoirs discovered follow the distribution rule and accumulation pattern of “near helium source, adjacent to fault, low potential area, and high position”. To explore and evaluate helium-rich areas, it is necessary to conduct concurrent/parallel exploration of natural gas. The comprehensive evaluation and selection of profitable helium-rich areas with the characteristics of “source-trap connected, low fluid potential and high position, and proper natural gas volume matched with helium’s” should focus on the coupling and matching of the helium “source, migration, and accumulation elements” with the natural gas “source, reservoir and caprock conditions”, and favorable carrier gas trap areas in local low fluid potential and high positions.
