Journal of Natural Gas Geoscience最新文献

Reservoirs of large platform margin mound-shoal complexes of the fourth member of Dengying Formation (Deng 4 Member) are developed in the margin of the Deyang-Anyue intra-cratonic rift in the Sichuan Basin and it is the main pay horizon of the Anyue gas field. A clear understanding of the reservoir genetic mechanism of the mound-shoal complexes is the key to predicting the distribution of high-quality reservoirs and guiding the deployment of exploration. Based on the data of drilling, seismic, outcrop, and analytical data, this paper analyzes the reservoir characteristics and genetic mechanism of the mound-shoal complexes at the margin of the Deng 4 Member and obtains three new understandings: (1) Platform margin mound-shoal reservoirs are developed on the margin of Deyang-Anyue intra-cratonic rift in Sichuan Basin. The mound-shoal complexes are mainly composed of algal mounds and bioclastic shoals in multiple stages. The reservoir space is mainly dissolution pores, caverns, and fractures, with low porosity and low permeability in general. (2) The reservoir can be divided into three types, i.e., the fracture-dissolution pore type, the dissolution pore type, and the matrix pore type, and the reservoirs of fracture-dissolution pore type are high-quality reservoirs; the development of reservoirs is mainly controlled by the platform margin mound-shoal complexes, the penecontemporaneous interstratal karst, and two-stage weathering crust karstification as well as multi-stage disruptive actions; the upper part of the reservoir in the same stage is good, and the reservoir at the top of Deng 4 Member is good. (3) Before the Himalayan movement, the reservoir forming and the environments of the two platform margin mound-shoal complexes were the same, and the characteristics of the formation of the reservoir were similar. The Himalayan movement led to a great difference in the current buried depth of the reservoir, resulting in a host of fractures and retaining a host of dissolution pores and caverns. The whole platform margin mound-shoal complexes have large-scale reservoirs developed and have a good exploration prospect. The results enrich the theory of ancient and deep carbonate reservoir forming and its genetic mechanism and provide the geological basis for the deployment of exploration.

Water, in ultra-deep layers of the earth and in layers receiving abnormally high heat, can exist in a supercritical state. Supercritical water (SCW) can participate in the transformations of organic compounds not only as a solvent but also as a reactant, influencing petroleum formation and the evolution of sedimentary organic matter. Here, we carried out hydrous pyrolysis experiments in both SCW and water vapor (WV) using two organic-rich marine rocks under closed conditions, to quantitatively evaluate the generation potential of hydrocarbons in a supercritical state and to clarify the effect of water phase on hydrous pyrolysis experiments. The results showed that SCW promoted gaseous and liquid hydrocarbon generation and facilitated the cracking of aliphatic hydrocarbons. For gaseous hydrocarbons, the action of SCW became stronger as the temperature increased. For liquid hydrocarbons, the peak yields of bitumen were enhanced by the SCW, and the temperature corresponding to peak yield in SCW was lower than that in WV. These results were attributed to the supply of hydrogen and oxygen from SCW for the petroleum formation and cracking. The δ¹³C and δD values of gases were also influenced by SCW. However, these values obtained in SCW did not always become positive as their yields increased. Generally, methane (CH₄) was enriched in ¹²C and ¹H. The influence of SCW on the isotopic fractionation of ethane (C₂H₆) and propane (C₃H₈) was more complex. The water phase is an important factor affecting the experimental results of hydrous pyrolysis. From these findings, it can be concluded that SCW allowed for increased conversion of sedimentary organic matter to gaseous and liquid hydrocarbons in ultra-deep layers and layers affected by volcanic-hydrothermal activity.

Based on the dissection of the geological characteristics of typical shale gas wells, the relationship between reservoir-forming factors and shale gas enrichment is deeply analyzed, and the controlling factors of shale gas enrichment are summarized. An analysis of data from drilling, logging, testing, and shale sample has revealed that the factors contributing to the formation of shale gas reservoirs in marine–continental transitional facies of Shanxi Formation in the southeast of Ordos Basin are highly heterogeneous. This is mainly reflected in the rapid spatial change of shale organic matter, physical properties, and other parameters of the shale in this area. The shale found in the Shanxi Formation has a high content of organic carbon (TOC), with an average of 2.24%. The kerogen type is mainly type Ⅲ, and the average value of R_O is 2.48%, indicating that it is in the high mature-overmature stage and is a high-quality source rock. The rock composition is rich in clay (40.5%–88.5%), mainly composed of illite-mongolian mixed layer and kaolinite, and its relatively high specific surface area is beneficial for improving the gas adsorption capacity of the shale. Thin sandstone interbeds, measuring less than 3 m are widely distributed in the Shanxi Formation and have good physical conditions. With an average porosity 3.37% and an average permeability of 0.1 mD. The natural gas generated by the shale can be transported to these sandstone interlayers (laminae) in a short distance, which is beneficial for improving the gas-bearing property of the shale. The gas-bearing property of the Shanxi Formation in the study area is affected by different lithologic assemblages. The gas-bearing property of the thick mudstone-coal assemblage of the second member of the Shanxi Formation is the best, with more than 80% of the samples having a gas content of over 1 m³/t. This study suggests that the high thermal evolution degree of shale, special marine–continental transitional facies reservoir conditions, and good preservation conditions are the main factors affecting the enrichment of shale gas in the study area. This makes the shale gas of the Shanxi Formation in the southeast of the Ordos Basin have certain potential for exploration and development, and delineates the enrichment targets of shale gas in the Zichang-Yan'an-Fuxian and Yichuan areas.

This study uses simulations to explore the energy distributions involved in the adsorption of methane gas in shales. Molecular mechanics calculations were carried out using the Forcite module in BIOVIA material studio software. The critical challenge in molecular-scale simulations remains the need to improve the description of the gas adsorption prior to up-scaling to a realistic scenario. Resolving this challenge requires the implementation of multi-scale techniques that employ atomistic/molecular-level results as input. Thus, it is pertinent that the appropriate molecular data on CH₄ gas interaction with shale is obtained. This study provides empirical data on CH₄ sorption/adsorption in shale at the molecular level to confirm the CH₄ storage potential of shales. The effect of pressure on the CH₄ sorption/adsorption was also investigated. A vital aspect of this study is elucidating the energy distribution and dominant energy that controls CH₄ sorption/adsorption to serve as a basis for the exploitation of CH₄ in productive shales. Following the intensive simulation exercise, the average total energy of CH₄ sorption varied from approximately −30 to −120 kcal/mol with increase in pressure from 500 to 2500 psi, suggesting increasing thermodynamic stability. The results indicated that van der Waals energy is the major sorption energy with values ranging from 60 to −250 kcal/mol as the sorption pressure increased, while electrostatic energy recorded the least contribution. The total adsorption energy increased from −5 to −16 kcal/mol for reservoir pressure range of 1–15 MPa. This energy distribution data confirmed the possibility of CH₄ adsorption on shale under reservoir pressure conditions.

The availability of hydrocarbons in the eastern part of Bangladesh indicates the presence of active petroleum systems in the Bengal basin. Although extensive research has been conducted in the Surma basin, the correlation between structural configuration, tectonostratigraphic framework, and hydrocarbon potentiality in the basin including Jaintiapur area has not yet been established. In this study, the hydrocarbon prospectivity of Jaintiapur and the adjoining Dupigaon area has been characterized through outcrop analogy with the subsurface interpretation of seismic data along L13-01, PK-SY-5, and L13-03 lines. The main three megasequences have been recognized based on sequence stratigraphy in the Sylhet region utilizing outcrop, seismic, and well-log data. The exposed Tertiary and Quaternary formations of Jaintiapur and adjoining areas can be classified into eleven litho-stratigraphic units. Detailed facies analyses indicate that these rock units were deposited in fluvial, deltaic, and shallow marine environments. The subsurface lithology of the study area has been inferred from the petrophysical data obtained from Sylhet-7, Kailashtila-4, and Jalalabad-1 wells. Jaintiapur area lies in a tectonically complex province and is controlled by the Dauki Fault System. Folding and faulting represent intense tectonic deformation in the area. Detailed analyses of surface and subsurface geology indicate that faults pass along the rivers and transverse faults segment the reservoirs. A total of seven horizons have been interpreted using Petrel software. The seismic attribute analysis identifies leads and prospects based on transverse faults and amplitude anomalies with distinct bright spots at the PK-SY-5 line. From seismic interpretation, attribute analysis, and lithofacies distribution of Sylhet-7 well and its surround area in the Dupigaon, it seems that same gas bearing sand. Gas sands of the Sylhet-7 well indicate the possibility of gas/oil in the equivalent sedimentary sequence in the Dupigaon structure as this area is located close to and more down-dip towards the kitchen area.

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.