Formation of low permeability reservoirs and gas accumulation process in the Daniudi Gas Field,Northeast Ordos Basin,China

The Daniudi Gas Field is a typical large-scale coal-generated wet gas field located in the northeastern Ordos Basin that contains multiple Upper Paleozoic gas-bearing layers and considerable reserves of gas. Based on integrated analysis of reservoir petrology, carbonate cement C–O isotope, geochemistry of source rocks and HC gas and numerical basin modeling, a comprehensive study focusing on the formation of low permeability reservoirs and gas generation process uncovers a different gas accumulation scene in Daniudi Gas Field. The gas accumulation discovered was controlled by the reservoir permeability reduction and gas generation process, and can be divided into two distinct stages by the low permeability reservoir formation time: before the low permeability reservoir formation, the less matured gas was driven by buoyancy, migrated laterally towards NE and then accumulated in NE favorable traps during Late Triassic to early Early Cretaceous; after the low permeability reservoir formation, highly matured gas was driven by excessive pressure, migrated vertically and accumulated in-situ or near the gas-generating centers during early to late Early Cretaceous. The coupling relationship between reservoir diagenetic evolution and gas generation process controlled on gas accumulation of the Daniudi Gas Field. This study will aid in understanding the gas accumulation process and planning further E&D of the Upper Paleozoic super-imposed gas layers in the whole Ordos Basin and other similar super-imposed low permeability gas layer basins.     

Geochemistry,origin, and accumulation of petroleum in the Eocene Wenchang Formation reservoirs in Pearl River Mouth Basin,South China Sea: A case study of HZ25-7 oil field

The Pearl River Mouth Basin in the South China Sea has accumulated >2 km of Eocene sediments in its deep basin, and has become the exploration focus due to the recent discoveries of the HZ25-7 oil field in the Eocene Wenchang (E₂w) Formation. In this study, the geochemical characteristics of potential source rocks and petroleum in the HZ25-7 oil field are investigated and the possible origins and accumulation models developed. The analytical results reveal two sets of potential source rocks, E₂w and Enping (E₂e) formations developed in the study area. The semi-deep-to-deep lacustrine E₂w source rocks are characterized by relatively low C₂₉ steranes, low C₁₉/C₂₃ tricyclic terpane (<0.6), low C₂₄ tetracyclic terpane/C₃₀ hopane (<0.1), low trans-trans-trans-bicadinane (T)/C₃₀ hopane (most <2.0), and high C₃₀ 4-methyl sterane/ΣC₂₉ sterane (>0.2) ratios. In contrast, the shallow lacustrine and deltaic swamp-plain E₂e source rocks are characterized by relatively high C₂₉ steranes, high C₁₉/C₂₃ tricyclic terpane (>0.6), high C₂₄ tetracyclic terpane/C₃₀ hopane (>0.1), variable yet overall high T/C₃₀ hopane, and low C₃₀ 4-methyl sterane/ΣC₂₉ sterane (<0.2) ratios. The relatively low C₁₉/C₂₃ tricyclic terpane ratios (mean value: 0.39), low C₂₄ tetracyclic terpane/C₃₀ hopane ratios (mean value: 0.07), high C₃₀ 4-methyl sterane/ΣC₂₉ sterane ratios (mean value: 1.14), and relatively high C₂₇ regular sterane content of petroleum in the HZ25-7 oil field indicate that the petroleum most likely originated from the E₂w Formation mudstone in the Huizhou Depression. One stage of continuous charging is identified in the HZ25-7 oil field; oil injection is from 16 Ma to present and peak filling occurs after 12 Ma. Thin sandstone beds with relatively good connectivity and physical properties (porosity and permeability) in the E₂w Formation are favorable conduits for the lateral migration of petroleum. This petroleum accumulation pattern implies that the E₂w Formation on the western and southern margins of the Huizhou Depression are favorable for petroleum accumulation because they are located in a migration pathway. Thus exploration should focus in these areas in the future.     

Quantitative analyses of porosity evolution in tight grainstones: A case study of the Triassic Feixianguan formation in the Jiannan gas field,Sichuan Basin,China

Tight grainstones, although widespread throughout the Lower Triassic Feixianguan Formation in the Sichuan Basin, have received little attention, in part, due to their lower porosity and greater heterogeneity relative to their dolostone counterparts. Based on data from cores and thin sections, as well as petrophysical properties, the Feixianguan grainstones, representing a major gas reservoir in the Jiannan gas field were systemically analysed to better understand porosity evolution in tight carbonates that have experienced original oil accumulation and subsequent thermal cracking during progressive burial. The grainstones were divided into two types according to whether pyrobitumen was present, and their porosity evolutions were quantitatively reconstructed. Taking 40% as the original porosity, the grainstones without pyrobitumen, which were ineffective palaeo-oil reservoirs, lost 21.94% and 3.13% of their porosities through marine and burial calcite cementation, respectively, and 13.34% by compaction, and have a current porosity of 1.59%, thus allowing them to serve as major present-day gas reservoirs. Comparatively, pyrobitumen-bearing grainstones, which were once palaeo-oil reservoirs, lost 23.96% and 2.36% of their porosities through marine and burial calcite cementation, respectively; 11.4% by compaction, and 1.44% by pyrobitumen and have a current porosity of 0.84%, thus making them ineffective gas reservoirs. This study provides a quantitative understanding of the close association between porosity evolution and reservoir effectiveness for the palaeo-oil charge and present-day gas accumulation with respect to diagenetic history, which is useful for the future exploration in tight gas limestone reservoirs.     

Impacts of the tectonic stress field on natural gas migration and accumulation: A case study of the Kuqa Depression in the Tarim Basin,China

Stress, fluid and temperature are three of the major factors that impact natural gas migration and accumulation. In order to study the influences of tectonic stress field on natural gas migration and accumulation in low-permeability rocks, we take the Kuqa Depression as an example and analyze the evolution of the structure and tectonic stress field at first. Then we study the influences of tectonic stress field at different tectonic episodes on fractures and fluid potentials through the numerical simulation method on the section across the KL2 gas field. We summarize two aspects of the impact of the tectonic stress field on natural gas migration and accumulation. Firstly, under the effects of the tectonic stress field, the rock dilation increases with the added stress and strain, and when the shear stress of rock exceeds its shear strength, the shear fractures are well developed. On one hand, the faults which communicate with the hydrocarbon source rocks become the main pathways for natural gas migration. On the other hand, these positions where fractures are well developed near faults can become good reservoirs for natural gas accumulation. Secondly, because fluid potentials decrease in these places near the faults where fractures are well developed, natural gas can migrate rapidly along the faults and accumulates. The impact of tectonic stress fields on natural gas migration and accumulation allows for hydrocarbon migration and accumulation in the low-permeability rocks in an active tectonic compressive setting.     

Numerical study of multi-period palaeotectonic stress fields in Lower Cambrian shale reservoirs and the prediction of fractures distribution: A case study of the Niutitang Formation in Feng'gang No. 3 block,South China

Fractures not only control the distribution of oil and gas reservoirs, but also are key points in the research of oil and gas reservoir development programmes. The tectonic fractures in the Lower Cambrian shale reservoirs in the Feng'gang No. 3 block are effective reservoir spaces for hydrocarbon accumulation, and these fractures are controlled by palaeotectonic stress fields. Therefore, quantitatively predicting the development and distribution of tectonic fractures in the Lower Cambrian shale reservoir is important for the exploration and exploitation of shale gas in the Feng'gang No. 3 block. In the present study, a reasonable geological, mechanical and mathematical model of the study area was established based on the faults systems interpreted from seismic data, fracture characteristics from drilling data, uniaxial and triaxial compression tests and experiments on the acoustic emissions (AE) of rocks. Then, a three-dimensional (3-D) finite element method is applied to simulate the palaeotectonic stress field with the superposition of the Yanshan and Himalayan movements and used to predict the fracture distribution. The simulation results indicate that the maximum principal stress value within the study area ranged from 269.97 MPa to 281.18 MPa, the minimum principal stress ranged from 58.29 MPa to 79.64 MPa, and the shear stress value ranged from 91.05 MPa to 106.21 MPa. The palaeotectonic stress field is controlled by the fault zone locations. The fracture development zones are mainly controlled by the tectonic stress fields and are located around the faults, at the end of the fault zones, at the inflection point and at the intersection of the fault zones.     

Nanoscale pore structure and fractal characteristics of a marine-continental transitional shale: A case study from the lower Permian Shanxi Shale in the southeastern Ordos Basin,China

Shale samples collected from seven wells in the southeastern Ordos Basin were tested to investigate quantitatively the pore structure and fractal characteristics of the Lower Permian Shanxi Shale, which was deposited in a marine-continental transitional (hereinafter referred to as the transitional) environment. Low-pressure nitrogen adsorption data show that the Shanxi Shale exhibits considerably much lower surface area (SA) and pore volume (PV) in the range of 0.6–1.3 m²/g and 0.25–0.9 ml/100 g, respectively. Type III kerogen abundant in the transitional Shanxi Shale were observed to be poorly developed in the organic pores in spite of being highly mature, which resulted in a small contribution of organic matter (OM) to the SA and PV. Instead, I/S (illite-smectite mixed clay) together with illite jointly contributed mostly to the SA and PV as a result of the large amount of inter-layer pores associated with them, which were evident in broad-ion-beam (BIB) imaging and statistical analysis. Additionally, the Shanxi Shale has fractal geometries of both pore surface and pore structure, with the pore surface fractal dimension (D1) ranging from 2.16 to 2.42 and the pore structure fractal dimension (D2) ranging from 2.49 to 2.68, respectively. The D1 values denote a pore surface irregularity increase with an increase in I/S and illite content attributed to their more irregular pore surface compared with other mineralogical compositions and OM. The fractal dimension D2 characterizing the pore structure complexity is closely related to the pore arrangement and connectivity, and I/S and illite decrease the D2 when their contents increase due to the incremental ordering degree and connectivity of I/S- or illite-hosted pores. Meanwhile, other shale constituents (including kaolinite, chlorite, and OM) that possess few pores can significantly increase the pore structure complexity by way of pore-blocking.