Journal of Natural Gas Geoscience最新文献

The Cambrian pre-salt has the accumulation conditions for forming a compound large gas province and was the strategic replacement area with the lowest exploration level and the largest exploration potential in the Tarim Basin. However, no significant discoveries have been found in the exploration for many years. The key problem is that the unclear controlling factors and spatial distribution of the hydrocarbon generation center and scale beach reservoir result in the ambiguity of favorable exploration directions and zones. Given this, a comprehensive application of seismic, drilling, well-logging, mud-logging, and geochemical data has been carried out to study the source-controlling, reservoir-controlling, caprock-controlling, and accumulation-controlling of the Cambrian pre-salt area, constructing the accumulation-controlling model and defining the favorable zones and exploration breakthrough direction. The following points have been gained: (1) Paleo-rifts controlled hydrocarbon generation center. The rift-depression structure formed in the Nanhua System to Sinian System provided the structural background for the development of the Lower Cambrian and controlled the deposition of the Cambrian Yuertusi Formation. In the negative tectonic area controlled by rifting, the thickness of the Yuertusi Formation was large and formed the hydrocarbon generation center. (2) The paleo-uplifts controlled the development of beach facies dolomite reservoir. The paleo-uplifts formed simultaneously with the Nanhua System paleo-rifts controlled the development and distribution of high-energy beaches in the Xiaerbulake Formation, and large-scale dolomitic beach facies reservoirs were formed on both sides of the Tanan paleo-uplift. (3) The paleo-depression controlled the development of gypsum-salt caprock. In the Middle and Late Cambrian, the Taxi platform has closed and formed a strong evaporation environment, while a wide-covering gypsum-salt caprock was deposited in the unified depression within the platform due to the development of the Luntai-Gucheng near the north-south rimmed platform margin. (4) The time-space matching of rift-uplift-depression controlled the formation and distribution of oil and gas. Three types of accumulation-controlling models, the stable rift-uplift-depression, the active rift-uplift-depression, and the transitional rift-uplift-depression, were established, indicating the stable and transitional areas as the main exploration directions, and the Aman low uplift between Awati Sag and Manxi Sag as the preferred target area for the large gas province in Cambrian pre-salt.

The Quaternary unconsolidated sandstone gas reservoir in the Qaidam Basin is characterized by multiple layers, strong heterogeneity, and active edge water. Based on these characteristics, a physical simulation experiment method for production from multi-layer edge-water gas reservoirs was proposed. In this method, the experimental models were established by using natural cores in series and parallel connection to show the geological characteristics of multi-layer gas reservoirs, and according to the results of the indoor simulation of the whole depletion production process, an experimental study on four layers of commingled production in one well was conducted under three scenarios of gas reservoirs: without the water invasion, with the water invasion without flow, and with the water invasion with flow. In this study, by visually monitoring the water invasion process of a constant-pressure edge water body along layers with different permeability and quantitatively analyzing the influence of gas well production allocation on the water invasion path and advancing speed of the water invasion front, the influence of non-uniform edge water invasion on gas reservoir productivity, recovery factors, and residual gas occurrence characteristics was clarified, and the mechanism of non-uniform edge water invasion along high permeability layers and the formation of water-sealed gas were revealed. The findings of this study can provide a basis for reasonable water control for this type of gas field.

The fault-karst carbonate reservoir in the Shunbei area of the Tarim Basin is controlled by deep strike-slip faults and forms a fault-karst system. The reservoir space primarily includes holes and fractures, and its strong anisotropism aggravates the complexity of the reservoir seismic response characteristics. High-quality reservoirs in the fault-karst body in this area have different burial depths, which is not conducive to the establishment of low-frequency models in traditional inversion. Facies-based Bayesian simultaneous inversion technology combines Bayesian classification with pre-stack simultaneous inversion, divides different facies based on multi-elastic parameters such as P-wave and S-wave velocity and density, and conducts an in-depth trend analysis for each phase to establish the initial model. Compared with traditional inversion technology, this technology not only improves the inversion accuracy but also increases the stability of the density inversion. Taking the carbonate fault-karst body in the northern section of the No.5 fault zone in the Shunbei area as the research object, combined with the actual production situation, two facies, fractured-cavity limestone, and tight limestone, were divided by elastic parameters and then subjected to depth trend analysis and inversion. Through the single fracture-cavity equivalent model test and practical application analysis, the density data obtained by the Facies based Bayesian simultaneous inversion were highly consistent with the reservoirs drilled by Wells W3 and W3C in the northern section of the No.5 fault zone, which verifies the applicability and reliability of the inversion technique in the study area and the reliability of the results.

Clarifying the deformation characteristics and formation mechanisms of the box fold in the eastern Qiulitage structural belt can provide important references for the reconstruction of the evolution process and petroleum exploration in the Qiulitage structural belt. As a result of the deep geological structure displayed by seismic data and characteristics of faults and fractures within the box fold, the mechanical mechanism and structural evolution of the box fold in the eastern Qiulitage structural belt were investigated, along with the genesis and significance of hydrocarbon exploration of faults and fractures within the box fold. The results show that the surface box fold in the Qiulitage structural belt was formed via the conjugate kinking of the supra-salt structural layer, driven by the intensive southward compression during the Middle and Late Himalayan movements. The box fold has experienced three evolution stages, namely, the tectonically-inactive stage before the deposition of the Kuqa Formation, the fold rudiment stage during the early to middle deposition of the Kuqa Formation (Kuqa period), and the stage of fold finalization and uplift-denudation. The front flank of the box fold develops north-dipping thrust faults and network fracture systems formed during the early to middle Kuqa period and cemented by gypsum due to the precipitation of deep, high-salinity formation water. However, later faulting can cut and dislocate the cement. The upper fold core develops north-dipping tensile faults and near EW tensile fractures, while the lower fold core is associated with small back-thrust structures and near NS shear fractures. The neutral plane is expected to be in the middle-lower part of the fold. The back-flank of the box fold develops south-dipping back-thrust faults and near EW interlayer shear fractures caused via interlayer detachment. The core and back flank of the fold were less affected by the high-salinity formation water, leaving faults and fractures with no considerable cementation. The kink zone and its surroundings have high storage and flow capacities and thus the potential to and develop oil and gas reservoirs. Correctly interpreting kink zones in concealed areas can help expand the scale of original oil and gas reservoirs or discover new petroleum exploration domains. In the Qiulitage structural belt, the connection between deep and shallow fault systems leads to the migration of deep hydrocarbons to shallow layers and subsequent accumulation. The structural-lithologic oil and gas reservoir formed in the Paleogene thin sand layers of the upper part of the Lower Cretaceous and the structural oil and gas reservoir formed in supra-salt sandstone layers of the surface box fold are among The potential exploration domains in shallow layers.

With ongoing advancements in natural gas exploration, the second member of the Sinian Dengying Formation (Deng 2 Member) has emerged as a crucial region for providing natural gas reserves in the north of the central Sichuan Basin. The Deng 2 Member has a significant volume of reservoir solid bitumen. Geochemical characteristics and development mechanism of the solid bitumen were determined through measurements and analyses of the Deng 2 Member samples collected from primary exploration wells by using optical microscopy, SEM, gas chromatograph-mass spectrometer, and laser Raman spectrometer. The results show that the Deng 2 Member has a generally high content of solid bitumen, ranging from 2.96% to 5.13% on average in single wells. The solid bitumen mainly occurs as the fillings of dissolved pores (caves) and fractures, followed by intergranular pores, in the shape of spots, balls, plates, and veins dominantly. Diasteranes content and laser Raman spectrograms indicate that the solid bitumen is in the high maturity stage. The bitumen reflectance calculated by laser Raman spectroscopy is distributed between 2.49% and 4.09%, indicating the major source of the thermal cracking of crude oil. Solid bitumen in the Deng 2 Member has different contents of 21α(H)–C₂₉ norhopane, C₃₅ hopane, and C₃₄ hopane, and Ts/Tm values from the Deng 4 Member in the Gaoshiti Moxi area. It is inferred that some solid bitumen is from the source rocks of the Lower Cambrian Maidiping Formation and the Sinian Doushantuo Formation. Two stages of bitumen were developed in the Deng 2 Member, indicating possible two stages of oil filling and thermochemical sulfate reduction (TSR) in the geologic history.

A semi-open system temperature-pressure controlled hydrocarbon generation and expulsion simulation experiment was carried out to explore the hydrocarbon generation and expulsion potential and mechanism of deep environment “coal measure” source rocks in the Qaidam Basin. A WYNN-3 high temperature and high pressure (HTHP) simulator and Middle Jurassic source rocks (III type organic matter, carbonaceous mudstone, and coal, R_O is 0.67% and 0.64%, respectively) of Well DMG1 in the northern margin of the Qaidam Basin were used during the investigation. The results demonstrated that: (1) The maximum total oil yields of carbonaceous mudstone and lignite, which respectively measured at 79.38 mg/g_TOC and 37.30 mg/g_TOC, revealed a “double peaks” evolution law as a whole. (2) In the lower evolution stages (T ≤ 300 °C, P ≤ 42.0 MPa), the expelled/discharged oil yields of the two types of source rocks were lower than those of the residual oil, and the hydrocarbon expulsion efficiencies were low. However, at 400 °C (51.0 MPa), they significantly increased reaching 76.84% and 83.72%, respectively. (3) The main group components of the discharged oil were resin and asphaltene, and the component yields were generally comparable to those of liquid hydrocarbons. The yields of expelled oil group components of carbonaceous mudstone were higher than those of coal. (4) The simulated gas was primarily composed of hydrocarbon gas and non-hydrocarbon gas (CO₂, N₂), and with the elevated thermal evolution, the yields of total hydrocarbon gas/gaseous hydrocarbon increased. The two types of source rocks had maximum hydrocarbon gas yield of 116.46 mL/g_TOC and 36.85 mL/g_TOC, respectively. (5) The vitrinite reflectance (R_O) increased as temperature and pressure conditions enhanced, and it exhibited good temperature consistency. The results of this temperature-pressure controlled simulation experiment showed that temperature was still the dominant factor in the thermal evolution of organic matter, fluid pressure had a “dual” control on the formation of type III organic hydrocarbon products, and “coal measures” source rocks still had a strong potential for hydrocarbon generation in the later stages of evolution. This research provided a certain data reference for the hydrocarbon generation and expulsion law of Jurassic deep “coal measures” source rocks in the northern margin of the Qaidam Basin.