Journal of Natural Gas Geoscience最新文献

The Cambrian subsalt dolomite in the Kalpin area of the Tarim Basin is an important reserve growth point and strategic replacement area. However, there is a lack of clear understanding regarding the formation mechanism of high-quality reservoirs in this region, which has hindered oil and gas exploration. This study aims to address this knowledge gap by providing a comprehensive description of the rock types and characteristics of the Xiao'erbulak Formation. Microscope observations, geochemical analyses, and interpretations of well logging data from Well KPN1 were used in this analysis. The Xiao'erbulak Formation can be divided into four members, arranged from bottom to top. The relatively high manganese (Mn) content (87–137.7 ppm), oxygen isotope composition (δ¹⁸O) with an average value of −6.37‰, and strontium isotope ratio (⁸⁷Sr/⁸⁶Sr) with an average value of 0.7109 indicate that dolomitization of the Xiao'erbulak Formation likely occurred during the penecontemporaneous-shallow burial period. The early formation of dolomite contributed to increased reservoir porosity and resistance to compaction during deep burial, which laid the foundation for reservoir formation. The carbon isotope composition (δ¹³C) of the Xiao 1 and Xiao 2 members exhibit frequent zigzag curves, indicating recurring progression/regression processes. The subsequent development of granular beach facies played a crucial role in reservoir formation in the Xiao 2 Member. Tectonic fractures and penecontemporaneous karstification controlled the reservoir characteristics of the Xiao 3 Member. Furthermore, this study provides an analysis of the diagenetic evolution model of Well KPN1 and examines the impact of diagenetic transformations on reservoir quality. The systematic analysis of downhole data from Well KPN1 serves as a foundational reference for comparative studies with other drilling sites in the area. It also offers valuable guidance for future exploration and deployment strategies in the northwest Tarim Basin.

In recent years, breakthroughs have been made in deep shale gas exploration in the Wufeng-Longmaxi formations in the complex tectonic region of the Sichuan Basin and southeastern margin, indicating promising prospects for exploration and development. This study focuses on the Nanchuan area of the complex tectonic region of the southeastern Sichuan Basin margin, using data from drilling wells and experimental analysis tests to investigate deep shale gas enrichment characteristics, particularly the effects of changes in the formation environment such as formation temperature and pressure on deep shale gas enrichment. The study concludes that: (1) The dominant sedimentary phase zone is the basis for hydrocarbon formation in shale gas reservoirs, with the Wufeng Formation–the first member of Longmaxi Formation in the study area—formed in a deep-water shelf sedimentary environment with high-quality shale development, which provides favorable material conditions for the formation of shale gas reservoirs. (2) Organic carbon content controls the degree of development of nanoscale organic matter pores, and the high-pressure-ultra-high-pressure environment helps maintain pores and improve the physical properties of deep shale. (3) Deep shale gas exhibits typical geological characteristics of high temperature, high ground stress, and exceptionally low permeability. The study finds the influence of temperature on the adsorption capacity of shale is more significant than that of pressure, and deep shale gas is primarily free gas. High pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (4) Gas diffusion is complex, with high temperature increasing the diffusion of gas, aggravating the migration and escape of gas, while high pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (5) The burial depth and pressure coefficient show a positive correlation, and the burial depth has a more significant effect on the pressure coefficient of syncline shale gas, indicating that preservation conditions of deep syncline shale gas reservoirs are becoming better. Residual syncline core with larger depths, inner-sag uplift, and slopes with reverse faults can be favorable targets for shale gas exploration in complex tectonic zones.

Transitional shale gas layers are widely distributed in China, but no significant exploration breakthrough has been made so far. This paper investigates and analyzes the characteristics and gas-bearing mechanisms of transitional shale gas reservoirs in detail, aiming to clarify the shale gas accumulation mechanism of transitional shale and provide theoretical support for the selection of favorable intervals. The transitional shale gas layer is characterized by a thin single-layer thickness, rapid lithological change, low brittle mineral content, and poor kerogen type. The lack of organic matter (OM) sponge pore development process from the oil-generation stage results in limited numbers of OM nanometer-scale pores. Shale pore space is dominated by pores and fractures related to clay minerals. The measured gas content is well consistent with the theoretically calculated gas content for marine organic-rich shales. However, the actual measured gas content is far lower than the theoretically calculated gas content for the transitional shale gas reservoir. The main mechanisms are summarized to be (1) the high hydrocarbon expulsion efficiency of the “sandwich” space structure of the sandstone–shale–coal association, which gives rise to most natural gas migrating into nearby sandstone, and (2) high water saturation resulting in insufficient storage space for free gas in the shale reservoir. Unlike marine shale gas, natural gas in the transitional shale reservoir is primarily dominated by adsorbed gas in kerogen, and free gas is relatively low. The favorable lithofacies types are organic-rich siliceous/calcareous shales. Multiple layers of siderite-bearing shales/siderites are developed vertically and continuously distributed horizontally in transitional strata, particularly in flat-lagoon facies. It is easy to form a “micro-trap” to store gas in siderite-bearing shale, and siderite-bearing shale has strong sealing properties due to low porosity, low permeability and high breakthrough pressure. This property can form overpressure and trap shale gas inside the shale, providing a new research perspective for the optimization of vertical favorable intervals, as well as exploration breakthrough in transitional shale gas. Further research should strengthen the systematic sedimentological study of transitional facies, reveal shale gas occurrence state and dynamic transformation, and optimize favorable interval evaluation systems to clarify the feasibility of coal-measure gas commingled production.

The Anambra Basin has a relatively high hydrocarbon production base compared with other Cretaceous basins in Nigeria. Structural deformation, overpressures, and faulting in the Cretaceous sequence of the Anambra Basin have resulted in significant uncertainties regarding reservoir parameters, necessitating accurate reservoir characterization. This study uses several subsurface data, including 2D seismic data, a report of core descriptions, and well log data from an exploration well drilled in the Anambra Basin to identify reservoirs and assess the petrophysical parameters of Cretaceous Formations for hydrocarbon accumulations. Three reservoirs were identified in the interpreted seismic section of the Cretaceous strata, and the structural framework was described as a system of synthetic faults dipping north-south that controlled the thickness and lateral extension of the deposited sediments. The shale volume, total and effective porosity, permeability, water, and hydrocarbon saturation were estimated using standard equations. The low shale volume, good-to-very good porosity values, fair-to-moderate permeability values, and low-to-moderate hydrocarbon saturation of the identified Cretaceous reservoirs suggest that the reservoir sands have the capacity to produce hydrocarbons. The density-neutron cross-plots of the identified reservoirs show a dual mineral system and also indicate the effect of gas in the Cretaceous reservoirs. This study found that the Anambra Basin has gas potential. However, the identified gas reservoirs should be further evaluated using reservoir pressure data, if available, to aid in accurate hydrocarbon fluid typing. The reservoirs should be developed and optimized in such a way as to keep production risk to its minimum.

To clarify the development rules and main origins of deep tight conglomerate reservoirs in the Mahu area of Junggar Basin, various materials and data from deep wells were systematically researched to determine the reservoir's basic characteristics and effective origins. The results indicate that the reservoir mainly comprises a fine and medium-fine conglomerate, which belongs to the fan delta distributary channel conglomerate. Additionally, it is a typical deep tight conglomerate reservoir with low to ultra-low porosity and permeability, and the gravel primarily consists of volcanic rock composed of tuff and intermediate acid volcanic lava. The cement is mainly composed of laumontite and calcite, and the reservoir has undergone three types of diagenesis: compaction, cementation, and dissolution. The first two types have dual effects of destruction and construction, while the result of dissolution is the widespread development of secondary pore enrichment zones composed of intergranular solution pores formed by the dissolution of zeolite, carbonate cement, and argillaceous matrix, as well as intragranular solution pores formed by the dissolution of feldspar and dark minerals. Unlike the middle and shallow layers, the reservoir space mainly composed of secondary pores and fractures. The effective reservoir is mainly caused by rock composition, dissolution, fracture system, and abnormal high pressure. The rock composition provides a sufficient material basis and is the internal cause, while the dissolution, fracture system, and abnormal high pressure are the external causes. The dissolution forms a secondary pore enrichment zone, the fracture system improves the seepage capacity of the reservoir, and abnormal high pressure can effectively maintain and increase the pores. Four factors control the formation and distribution of relatively high-quality deep tight conglomerate reservoirs.

Ultra-deep carbonate gas reservoirs are buried at great depths and have high temperatures, and the impact of high temperature on the seepage capacity of multi-type reservoirs is still unclear. The study selected cores from the fourth member of Dengying Formation in the Gaoshiti-Moxi area to measure the gas single-phase permeability of rock samples during the heating and cooling process, as well as the gas-water interfacial tension and gas-water two-phase relative permeability at different temperatures. This allowed researchers to obtain the effect of temperature on the seepage capacity of multi-type ultra-deep carbonate gas reservoir. The research results show that within the range of 20–120 °C, with the change of temperature, the gas single-phase seepage capacity of different types of reservoir rock samples changes as a power function. The decrease in gas-phase permeability during the heating process is jointly affected by the increase in gas viscosity, the expansion of dolomite crystals, and the migration of rock particles after embrittlement. After one heating and cooling process, fractured-cavity type rock samples had the highest irreversible degree of permeability at 82.52%, due to the development of micro-fractures, followed by 27.63% for pore type due to the development of small pores and throats, and the lowest was 9.46% for pore-cavity type. Fractured-cavity rock samples are temperature-sensitive, while pore-type and pore-cavity-type rock samples are temperature-resistant. The upper-temperature limit of the target multi-type gas reservoir is concentrated around 46–50 °C. The temperature increase mainly improves the gas-displacing water efficiency and gas-water two-phase seepage capacity by reducing the water-gas viscosity ratio, which is about 1/3 of the normal temperature at the formation temperature. The gas-water phase permeability curves of multi-type reservoirs under high-temperature conditions can better represent the two-phase seepage characteristics of actual formations. The effect of temperature on the seepage capacity of multi-type ultra-deep carbonate gas reservoirs can provide a theoretical basis for the efficient development of such gas reservoirs.

In recent years, significant advancements have been achieved in the exploration of natural gas around Shawan Sag in the Junggar Basin. However, the geochemical characteristics and distribution of source rocks in the center of the sag have yet to be thoroughly researched, and there is a lack of understanding regarding the evolution history of hydrocarbon generation and the characteristics of each set of source rocks. This has posed limitations on future exploration and development initiatives in the area. The study focused on source rock samples from the uplift zone and conducted a comprehensive evaluation through seismic and hydrocarbon generation thermal simulation experiments. This allowed for clarification of the product characteristics of source rocks in different strata and pointing out the direction for future natural gas exploration. The results showed the presence of four sets of well-developed source rocks in Shawan Sag, characterized by their extensive thickness, wide distribution, and deep burial, laying a material foundation for oil and gas accumulation in peripheral structures. The Carboniferous and Jiamuhe Formation source rocks have high organic matter abundance, but the quality is poor and the potential for generating hydrocarbons is low, leading mainly to the generation of dry gas. On the other hand, the Fengcheng Formation and Lower Wuerhe Formation source rocks have high organic matter abundance and good quality, and are highly mature, resulting in high potential for generating hydrocarbons. The δ¹³C₁-R_O regression equation of natural gas in Shawan Sag was established, and the carbon isotope distribution patterns of ethane generated from source rocks in different layers were identified, providing a foundation for determining the maturity of natural gas and correlating the sources of gas in surrounding structures. The west slope of Shawan Sag has favorable preservation conditions and is located on a hydrocarbon migration pathway, similar to the slope of Mahu Sag. This area also has favorable geological conditions for the formation of large lithologic reservoirs, making it a key field for gas exploration in the study area moving forward.

A remarkable characteristic of the Bandar Abbas Hinterland is the frequent presence of oil seepages that can serve as an indicator of probable oilfields in the region. The Seeps A and B are located in the main Zagros Suture Zone, 150 km to the northeast of Bandar Abbas and 30 km to the west of the same city, respectively. The presence of well-known Paleozoic source rocks (e.g., Seyahou, Sarchahan, and Gurpi formations) in the vicinity of the mentioned oil seepages shows that the seeping oil is coming from an oil source. The present research is aimed investigating the petroleum system and determining the source of the mentioned oil seepages. Results of the Rock-Eval analyses showed that the samples of the Seyahou Formation are thermally overmatured, making them exhibit inadequate oil generation potential. These samples contain Type-III kerogen and were found to be in the metagenesis stage. However, compared to other formations, Sarchahan and Gurpi exhibited good hydrocarbon generation potentials. On the other hand, based on the PI – T_max diagram, the Sarchahan Formation was found to be in the early oil and condensate production window (i.e., catagenesis stage) while the Gurpi Formation was seen to be immature. Biomarker analysis results showed that the samples were deposited in a mixed marine environment and contained Type-II and Type II/III kerogen. The reason behind the occurrence of the oil seepages in an oxidative environment could be the sever impact of the biological degradation. The stable carbon isotope composition of the crude samples supported the biomarker data in general. Therefore, it can be concluded that the studied oil seepages were probably sourced from the Sarchahan Formation.

The ultra-deep-buried fractured tight gas reservoir in the Kuqa Depression of the Tarim Basin has developed edge and bottom water. Faults and fractures have become “highways” for water invasion, resulting in the “water sealed gas” effect and reducing gas reservoir recovery. At present, there is a lack of effective evaluation methods. Therefore, based on an analysis of water invasion characteristics of the gas reservoir, a dynamic evaluation method for water-sealed gas in a fractured gas reservoir is established. This method considers two factors: fracture development scale and peripheral water body strength. It is then applied to three developed blocks in the Kuqa ultra-deep layer. The effectiveness of the evaluation results is verified by static and dynamic combination, and countermeasures to improve gas reservoir recovery are proposed. The results indicate that: (1) The non-uniform water invasion of fractures is jointly controlled by structural position, fracture development degree, and fracture network combination, which can be divided into three modes: edge water channeling along the large fracture in the core, edge and bottom water invading along the fracture in the wing, and rapid, violent water flooding of the bottom water along the fracture/small fault in the low part. (2) The replacement coefficient of water invasion in the three typical blocks is 0.2–0.3, indicating that they are sub active water-gas reservoirs. However, the severity of water-sealed gas varies greatly. The more severe the water-sealed gas is, the lower the recovery factor of the gas reservoir. (3) For directionally penetrating large fracture gas reservoirs, water shutoff should be carried out. For fracture network gas reservoirs with high fracture density, mild exploitation can control water, and early drainage can reduce the impact of water invasion, improving gas reservoir recovery. It is concluded that the new method of water-sealed gas dynamic evaluation can provide a reliable basis for evaluating fracture non-uniform water invasion dynamics of the ultra-deep gas reservoir and enhancing oil recovery of the gas reservoir in the Kuqa Depression. This method also supports the formulation of water control policies and the economic and efficient development of ultra-deep gas reservoirs in the Kuqa Depression.

Methyltrimethyltridecylchromans (MTTCs) are biomarkers that are commonly used to identify immature-low mature source rocks or crude oil. MTTCs are abundant in the mature crude oils found in the Machang area of the southern Dongpu Depression in the Bohai Bay Basin. To explore the mechanism behind the enrichment of MTTCs in mature crude oils, a detailed study was conducted to investigate their distribution characteristics in crude oil samples. The study integrated tectonic evolution history, distribution characteristics, and thermal history of source rocks, molecular fingerprints characteristics of crude oils, and catalytic characteristics and combination features of clay minerals in the wall rock of crude oils. Based on this analysis, two enrichment models were proposed: (1) The first model suggests that crude oils were mixed with a small amount of immature-low mature soluble bitumen containing MTTCs; (2) The second model proposes that the evolutionary mechanism of clay minerals in the reservoir could reduce the decomposition rate and degree of MTTCs, resulting in their relative enrichment. Therefore, this study provides insights into the enrichment mechanism of MTTCs in mature crude oils and highlights the importance of considering various factors, such as tectonic evolution history, source rock characteristics, and catalytic properties of clay minerals, to understand the distribution and enrichment of biomarkers in crude oils.