Journal of Natural Gas Geoscience最新文献

Hydrocarbon accumulation in coal measure strata is consist of several types which includes intra-source accumulation and adjusted accumulation, particularly in basins that had experienced multi-stage tectonic activities. The mechanism governing this accumulation is extremely complex. Using the Paleozoic petroleum system in the Huanghua Depression as an example, the mechanism of hydrocarbon accumulation in deep reservoirs can be revealed by means of core observation, geochemistry testing of coal measure source rock, thin section observation, fluid inclusions testing, and profile analysis of typical reservoirs, combined with the burial and thermal history of strata. Based on the regional tectonic, the mechanism of hydrocarbon accumulation in coal measures is defined and the accumulation model was established. The results show that the Paleozoic petroleum system in the Huanghua Depression has three different types of source-reservoir-cap assemblages: under-source, intra-source, and above-source assemblage. Regional tectonic evolution controlled the hydrocarbon generation process of source rocks, showing the hydrocarbon generation characteristics of “oil in the early stage and gas in the late stage.” The Middle Cretaceous is the first of two periods of hydrocarbon accumulation, during which stage occurred in low-maturity oil and a small amount of natural gas were mainly stored in intergranular pores and dissolution pores. The tectonic uplift in the Late Cretaceous caused the destruction of the ancient reservoir. The second accumulation stage occurred in the Middle Paleogene to the present. A large amount of natural gas and high maturity oil were mostly stored in dissolution pores and structural fractures. The hydrocarbon accumulation in Huanghua Depression was simultaneously regulated by reservoir reformation, tectonic activities, and source rock maturation. Based on the foregoing understanding, the hydrocarbon accumulation model of “oil and gas transfer station” in coal measures is put forward, that is, oil and gas are first accumulated in intra-source or near-source reservoirs, and are then adjusted from this “oil and gas transfer station” to other areas as a result of tectonic activity.

Due to a great increase in the plasticity of deep marine shale reservoirs in southern Sichuan under high-temperature and high-pressure conditions, the single brittleness evaluation method is difficult to effectively characterize its fracability, which significantly limits the selection of sweet spots and fracturing reconstruction in the area. In the case of the deep marine shale reservoir of the Wufeng-Longmaxi formations in the southern Sichuan Basin, through triaxial high-temperature and high-pressure experiments, fracture toughness and X-ray diffraction experiments, the mechanical properties and its influencing factors in the shale reservoir are studied, and the rock fracture morphology under various loading conditions is quantified. According to the morphological characteristics of shale, the analysis of influencing factors and comprehensive quantitative evaluation of the brittleness has been carried out. The deep marine shale resource in the southern Sichuan Basin is likely to be characterized by its high elastic modulus and low I fracture toughness. The mineral composition, temperature, pressure, and degree of bedding development are the primary factors for determining the brittleness; with high quartz mineral content (>50%), low confining pressure (<20 MPa), medium and low temperature (<60 °C) and high density of the shale bedding, the fractal dimension of the sample after the experiment is higher; whereas the geometry of cracks are mainly complex shear cracks, and brittleness is higher. The analytic hierarchy approach establishes a comprehensive evaluation index by analyzing the relationship between the normalized rock mechanical parameters, the stress–strain curve's brittleness index, and the fractal dimension. The brittleness of deep marine shale can be more accurately described by this evaluation index. The primary target layer for future shale gas exploitation, the 3¹ sublayer of the first member of the Longmaxi Formation, is shown to have a high brittleness index.

Recently found substantial discoveries in the Lower Jurassic Sangonghe Formation in Taibei Sag, Turpan-Hami Basin was made possible through exploration wells Qintan1 and Ji7H. The two wells represented a major breakthrough in lithologic oil and gas reservoir exploration in the depression area and offered promising results for the investigation of the “lower depression source” in the Turpan-Hami Basin. The two favorable conditions of lithologic reservoir formation in the sag area are systematically summarized based on the two wells, and specific suggestions for further exploration are specified. The results show that: (1)Three sets of source rocks, namely Badaowan Formation, Sangonghe Formation, and Xishanyao Formation, are developed in Shuixigou Group of Jurassic in Taipei Sag. The new drillings reveal that Sangonghe Formation serves as both a regional caprock and a high-quality source rock. According to the source rock re-evaluation, the Shuixigou Group in Taipei Sag has excellent hydrocarbon generation potential. (2)Sangonghe Formation of Lower Jurassic is the main target layer for exploration in the depression area. Braided river delta sediments are developed. Sandbodies are developed in the depression area. At a depth of more than 5000 m, effective reservoirs are still developed as a result of secondary dissolution and structural fractures. (3)There are five favorable zones of rock reservoirs in the Lower Jurassic of Taibei Sag, namely, Pudong, Hongbei, Lingbei, Qiudong, and Gebei. These zones have excellent exploration potential and represent an important direction for future exploration in the Turpan-Hami Basin.

Helium, a coordinated resource in natural gas, is an essential and strategic resource, but research on its enrichment mechanism is relatively weak. This study investigated helium enrichment in major reservoirs in China using geochemical methods to address the challenging topic of how helium accumulates in helium-rich gas reservoirs. It concludes that helium is enriched in a few reservoirs which capture additional helium exsolution from ancient groundwater. Released dissolved helium from ancient groundwater into the reservoir is the main mechanism of helium accumulation in helium-rich gas reservoirs. This was the first time that the concept of “multiple sources of helium supply and primary sources of helium enrichment” was applied to guide the formation of helium-rich gas reservoirs. Moreover, the main sources of helium comes from the radioactive decay of uranium (U) and thorium (Th) in hydrocarbon rocks, reservoirs, and the decay of U and Th dissolved in groundwater from other rocks. When dissolved helium in ancient groundwater crosses free gas or gas reservoirs, the partial pressure of helium in the water is significantly higher than the partial pressure of helium in the free gas or gas reservoirs, proving Henry's Law which states that the helium in the water is almost completely exsolution into the gas reservoir, forming a helium-rich gas reservoir.

The deep strata of the northern margin of the Qaidam Basin are currently unexplored and have high resource potential. To clarify the characteristics and control factors of the deep sandstone reservoir in the study area, a comprehensive investigation of the Xiaganchaigou Formation deep reservoir in the northern Qaidam margin is carried out using the casting thin section, SEM, porosity and permeability measurements, and well logging and mud logging data. The results show that the feldspar lithic sandstone and lithic feldspar sandstone, which are well sorted and medium-rounded and have high compositional and textural maturities, make up the majority of the deep reservoir rock of the Xiaganchaigou Formation in the northern Qaidam margin. Extensive development of primary pores is observed and the porosity and permeability are well correlated with each other, with the average porosity and permeability of 10.7% and 25.74 × 10⁻³ μm², respectively. The pore-throat has excellent connectivity and is medium-fine in texture. The sands of the braided river delta front underwater distributary channel deposition and the sheet sands of the shore-shallow lake deposition are the basis for the formation of high-quality reservoirs. The carbonate cement is subjected to prolonged early shallow burial and late rapid burial during the diagenesis, effectively protecting primary pores. Feldspar particles and early carbonate cement are partially dissolved during the telodiagenesis, improving the physical properties of the reservoir by generating a certain number of inter- and intra-granular dissolved pores. Thick mudstone layers are deposited both above and below the sandstone reservoir. The drainage of pore fluids from the sandstone reservoir is therefore suppressed during the deposition-diagenesis and rapid burial, trapping the fluids in the pore space to bear part of the overburden pressure. This reduces the effects of normal compaction on the reservoir rock and helps in the preservation of primary pores to a large extent. The abnormal pressure zone in the Palaeogene Xiaganchaigou Formation, which develops the under-compacted mudstone of the braided river delta deposition, is found in the central part of the northern Qaidam margin and is afavorable play for natural gas exploration and development.

Ultra-low permeability–tight sandstone (gravel) gas reservoir is an important exploration target for natural gas both domestically and internationally. As a crucial oil and gas exploration basin in China, the Bohai Bay Basin has discovered tight sandstone (gravel) gas in every depression. However, the distribution, origin, and accumulation model of tight sandstone (gravel) gas reservoirs were not systematically studied by previous researchers, who instead mainly concentrated on depressions from the basin-wide perspective. The research conclusively demonstrates that ultra-low permeability–tight sandstone (gravel) gas reservoirs are widely distributed in the Bohai Bay Basin, covering various depressions and multiple strata of Paleozoic, Cenozoic, and Upper Paleozoic coal-formed gas as well as Paleogene oil-type gas. The Upper Paleozoic ultra-low permeability–tight sandstone gas reservoirs are mainly distributed in residual Upper Paleozoic strata of the Huanghua, Linqing, and Jiyang depressions. Most of those reservoirs, which are located in uplifted sag zones, are structural gas reservoirs, and because the strata were buried deeply in the past, most of the reservoirs have worse physical properties. This natural gas is typical coal-formed gas originating in Carboniferous and Permian, and others are Paleogene oil-type gas. Paleogene ultra-low permeability–tight gas reservoirs are widely distributed in all depressions, including the multiple strata in the Kongdian Formation and the second, third. and fourth members of the Shahejie Formation (Es₂, Es_3, and Es₄); The gas reservoirs are located in the uplift, slope, and steep slope zones of the sags, including a variety of trap types, such as lithology, lithology-structure, structure reservoirs, and others. Sandstone reservoirs often found in the Es₂ and Es₃ are distributed in gentle slopes, whereas sandstone and glutenite reservoirs can be found in the Es₄ and Kongdian Formation (Ek), with the glutenites mainly distributed in steep slope area. Since the Paleogene is a continuous deposit, burial depth appears to be a controlling factor in the reservoirs physical properties. Densification threshold depths for distinct depressions range from 3200 m to 4000 m. The majority of the natural gas is gas formed from Paleogene oil-type, while some of it is gas formed from Upper Paleozoic coal. Four different hydrocarbon accumulation models have been developed in this area in accordance with the relationship between gas sources and reservoirs. These models include migration along fault with old source rock and new reservoir, near-source accumulation with new source rock and new reservoir, distant-source accumulation with old source rock and old reservoir, and migration along fault with new source rock and old reservoir, of which the first two are the main hydrocarbon accumulation