Petroleum Exploration and Development最新文献

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.