Hydrocarbon Charging and Accumulation in the Permian Reservoirs of the Wumaying Buried Hill, Huanghua Depression, Bohai Bay Basin, China

The Wumaying buried hill experienced multi-stage tectonic movements, which resulted in a complicated and unclear nature of the hydrocarbon accumulation process. To solve these problems, in this study—based on the structural evolution and burial–thermal history of the strata, using petrology, fluid inclusion microthermometry, geochemical analysis of oil and gas, Laser Raman spectrum, and fluorescence spectrum—the history of hydrocarbon charging was revealed, and the differences in hydrocarbon charging of different wells was clarified. The results indicate that the only source for Permian oil and gas reservoirs are Carboniferous–Permian coal-measure source rocks in the Wumaying buried hill. There are three periods of hydrocarbon charging. Under the channeling of faults and micro cracks, low-mature oil and gas accumulation was formed in the first period, and the accumulation time was 112–93 Ma. In the late Cretaceous, a large-scale uplift exposed and damaged the reservoirs, and part of the petroleum was converted into bitumen. In the middle–late Paleogene, the subsidence of strata caused the coal-measure to expel mature oil and gas, and the accumulation time of mature oil and gas was 34–24 Ma. Since the Neogene, natural gas and high-mature oil have been expelled due to the large subsidence entering the reservoir under the channeling of active faults; the accumulation time was 11–0 Ma. The microfractures of Permian reservoirs in the Wumaying buried hill are the main storage spaces of hydrocarbons, and the fractured reservoirs should be explored in the future. The first period of charging was too small and the second period was large enough in the WS1 well, resulting in only a late period of charging in this well.

Hydrocarbon Retention and the Case for Vertical Migration

Complex hydrocarbon charging and distribution in which reservoirs are filled by oil and gas phases with different densities and genetic types inter-fingering within the basin, are common phenomena, and often attributed to vertical migration. This paper discusses the factors that control vertical hydrocarbon migration and presents modelling of the hydrocarbon charging and entrapment history in a tertiary basin in Southeast Asia as a case study. According to the Young-Laplace flow theory of the secondary hydrocarbon migration mechanics, migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. In this study, the invasion percolation simulation algorithm, based on the Young-Laplace flow, was used. During the simulation, three-dimensional (3D) seismic data were used as the high-resolution base grid for migration to capture the effect of both structure and facies heterogeneities on fluid flow. A model of an unfaulted system was presented to make the case. In the study area there is inter-fingering between oil and gas across different formations; most oils are trapped in the deeper formation, oil and gas inter-fingering occurs in the middle formation, and the upper formation contains mostly gas. This arrangement is possible because of the interplay between the expelled fluid buoyancy and relatively weak intra-formational seals within the basin. The modeling results were then calibrated to known accumulations or fluid presence in wells. In a basin dominated by a vertical migration regime, hydrocarbons are prevented from travelling far from the kitchen, thus decreasing prospectivity away from the kitchen. Through a case study, this paper helps to understand the factors that influence hydrocarbon retention and migration that control fluid distribution within a basin. Eventually the study helps geologists to understand prospectivity risking related to hydrocarbon charging, which is one of the main risks in exploration especially in mature basins.

Effect of Diagenetic Evolution and Hydrocarbon Charging on the Reservoir-Forming Process of the Jurassic Tight Sandstone in the Southern Junggar Basin, NW China

Deeply buried sandstones in the Jurassic, Toutunhe Formation, are a crucial exploration target in the Junggar Basin, NW China, whereas, reservoir-forming process of sandstones in the Toutunhe Formation remain unknown. Focused on the tight sandstone of the Toutunhe Formation, the impacts of diagenesis and hydrocarbon charging on sandstone reservoir-forming process were clarified based on the comprehensive analysis of sedimentary characteristics, petrography, petrophysical characteristics, and fluid inclusion analysis. Three diagenetic facies developed in the Toutunhe sandstone reservoirs, including carbonate cemented facies (CCF), matrix-caused tightly compacted facies (MTCF), and weakly diagenetic reformed facies (WDF). Except the WDF, the CCF and the MTCF entered the tight state in 18 Ma and 9 Ma, respectively. There was only one hydrocarbon emplacing event in sandstone reservoir of the Toutunhe Formation, charging in 13 Ma to 8 Ma. Meanwhile, the source rock started to expel hydrocarbons and buoyancy drove the hydrocarbon via the Aika fault belt to migrate into sandstone reservoirs in the Toutunhe Formation. During the end of the Neogene, the paleo-oil reservoir in the Toutunhe Formation was destructed and hydrocarbons migrated to the sandstone reservoirs in the Ziniquanzi Formation; some paleo-oil reservoirs survived in the WDF. The burial pattern and change of reservoir wettability were major controlling factors of the sandstone reservoir-forming process. The buried pattern of the Toutunhe Formation in the western section of the southern Junggar Basin was “slow and shallow burial at early stage and rapid and deep burial at late stage”. Hence, pore capillary pressure was extremely low due to limited diagenetic reformation (average pore capillary pressures were 0.26 MPa). At the same time, high content of chlorite coating increased the lipophilicity of reservoirs. Therefore, hydrocarbons preferably charged into the WDF with low matrix content (average 4.09%), high content of detrital quartz (average 28.75%), high content of chlorite films (average 2.2%), and lower pore capillary pressures (average 0.03 MPa). The above conditions were favorable for oil and gas enrichment.

Determination of Formation Time of Calcareous Cements in Marine Sandstone and Their Influence on Hydrocarbon Accumulation: A Case Study of the Carboniferous Donghe Sandstone in the Hadexun Oilfield, Tarim Basin

Based on core observations, the microheterogeneity, diagenetic features, diagenetic mineral compositions, and stable isotopes of cements in the calcareous interlayers in the Donghe sandstone were studied by polarizing microscopy, cathodoluminescence microscopy, X-ray diffractometry, isotope ratio mass spectrometry, and other techniques. By determining the proportions of cements of two phases by a statistical method and their clumped isotope values by an end-member method, the multiphase calcareous cementation was shown to be the major contributor to densification. Cluster isotopes revealed that the average formation temperatures of calcareous cements in phases II and III of cementation were 45–50°C and 80–90°C, indicating that they were products of the A and B phases during early diagenesis, respectively. According to the homogenization temperatures of coeval salt-water inclusions associated with hydrocarbon inclusions, which range from 100°C to 130°C, basin modeling revealed that the basin underwent mainly one stage of hydrocarbon charging during 8–5 Ma in the Miocene period. The cements of the two phases in the oil-free calcareous interlayers in the Donghe sandstone, which are the main controlling factor of the oil-water distribution in the reservoir at present, formed much earlier than the oil filling in the oil-bearing sandstone.

Fault Mesh Petroleum Plays in the Donghetang Area, Tabei Uplift, Tarim Basin, Northwestern China, and Its Significance for Hydrocarbon Exploration

— The hydrocarbon formation mechanism and potential targets in clastic strata from the Tabei Uplift, Tarim Basin, are documented using the fault mesh petroleum plays theory, based on integrating seismic, well log, well core, and geochemical data. The reservoirs in the Donghetang area are typical allochthonous and far-source fault mesh petroleum plays. There are two sets of fault meshes in the study area: (1) the combination of the Donghe sandstone and Permian–Triassic strata and (2) the combination of the fourth and third formations in the Jurassic strata. The fault mesh petroleum play in the Jurassic is a secondary reservoir that originates from the Carboniferous Donghe sandstone reservoir adjustment based on source correlation. The fault mesh carrier systems show the fully connected, fault–unconformity–transient storage relay, fault–transient storage–unconformity relay, and transient storage–fault relay styles, according to the architecture of the fault mesh. Based on the characteristics of the fault mesh petroleum plays, the reservoirs are divided into three categories (upper-, inner-, and margin-transient storage styles) and 15 styles. Integrated analysis of the hydrocarbon generation and faulting time periods reveals that there were four periods of hydrocarbon charging, with the first three stages charging the reservoirs with oil and the last stage charging the reservoirs with gas. There are multiple stages of reservoir accumulation and adjustment in the fault mesh in the study area. These stages of fault mesh accumulation and adjustment are the main reason why the reservoir distribution multiple vertical units have different hydrocarbon properties. Fault-block and lithologic reservoirs related to the inner- and upper-transient storage styles are the main exploration targets in the clastic strata in the study area.

Differential hydrocarbon enrichment in deep Paleogene tight sandstones of the Dongpu Depression in Eastern China

To clarify the characteristics and enrichment rules of Paleogene tight sandstone reservoirs inside the rifted-basin of Eastern China, the third member of Shahejie Formation (abbreviated as Es3) in Wendong area of Dongpu Depression is selected as the research object. It not only clarified the geochemical characteristics of oil and natural gas in the Es3 of Wendong area through testing and analysis of crude oil biomarkers, natural gas components and carbon isotopes, etc.; but also compared and explained the types and geneses of oil and gas reservoirs in slope zone and sub-sag zone by matching relationship between the porosity evolution of tight reservoirs and the charging process of hydrocarbons. Significant differences have been found between the properties and the enrichment rules of hydrocarbon reservoirs in different structural areas in Wendong area. The study shows that the Paleogene hydrocarbon resources are quasi-continuous distribution in Wendong area. The late kerogen pyrolysis gas, light crude oil, medium crude oil, oil-cracked gas and the early kerogen pyrolysis gas are distributed in a semicircle successively, from the center of sub-sag zone to the uplift belt, that is the result of two discontinuous hydrocarbon charging. Among them, the slope zone is dominated by early conventional filling of oil-gas mixture (at the late deposition period of Dongying Formation, about 31–27 Ma ago), while the reservoirs are gradually densified in the late stage without large-scale hydrocarbon charging (since the deposition stage of Minghuazhen Formation, about 6–0 Ma). In contrast, the sub-sag zone is lack of oil reservoirs, but a lot of late kerogen pyrolysis gas reservoirs are enriched, and the reservoir densification and hydrocarbon filling occur in both early and late stages.