2021 Vol. 32, No. 4
In the Middle and Upper Yangtze region of South China, there are well developed sets of marine shale strata. Currently only Wufeng Longmaxi shale gas has been developed in scale, while the Sinian and Cambrian shale gas are still under exploration. The various shale strata show different characteristics in lithological features, such as lithofacies types and reservoir physical properties, which are due to the influence of tectonic pattern, sedimentary environment, and diagenesis caused by tectonic subsidence. This will affect the later fracturing technology and fracturing effect. The shale reservoirs of Sinian doushantuo, Cambrian Niutitang, Upper Ordovician Wufeng, and the Lower Silurian Longmaxi Formation shale were evaluated and compared with each other with respect to their sedimentary environments, lithofacies, minerals compositions, and micro pore characteristics. The reservoir characteristics of the shale and the main control factors of shale gas enrichment were summarized in this study.
There are widespread Mesozoic-Cenozoic terrestrial volcanic activities in East China, and they produced favorable geologic factors for the volcanic reservoirs. To reveal the spatio-temporal evolution of regional volcanisms and their tectonic setting, we subdivide Mesozoic-Cenozoic volcanic activities into 6 volcanic cycles (Ⅰ-Ⅵ), and summarize the temporal-spatial distribution, rock association and tectonic setting of each cycle. The Cycle I forms a post-orogenic intraplate bimodal volcanic association. The cycles Ⅱ and Ⅲ include arc volcanic associations formed in compressional and extensional subduction environments, respectively. The Cycle Ⅳ contains a post-orogenic arc bimodal association. The Cycle Ⅴ is a basaltic association of tholeiite series under initial rift setting, and the Cycle Ⅵ is basaltic association of alkaline series under typical rift setting. The volcanic strata between each cycle are bounded by regional unconformity. The above 6 volcanic cycles correspond to 6 sequential stages of tectonic evolutions from the Early Jurassic post-orogeny, the Mid-Jurassic-Cretaceous subduction of the paleo-Pacific Plate to the Cenozoic marginal rifting. According to the geological characteristics of volcanic reservoirs in different volcanic cycles, it is put forward that the Cycle Ⅴ is the major formation period of volcanic reservoirs in East China and should be the focus of exploration, and that the volcanic reservoirs of the Cycle Ⅳ are also worthy of attention.
Taking the shale of Shuijingtuo Formation of Lower Cambrian in Yichang area as the research object, the shale reservoir characteristics are comprehensively evaluated and classified by fitting regression and formula calculation method in this study, using laboratory testing and geophysical logging data. The results show that the interpretation data of ECS (elemental capture spectroscopy) logging has a high correlation with the measured minerals data, which can be a good method to evaluate the minerals component of the shale. The calculated content of brittle minerals at the lower part of Shuijingtuo Formation is the relatively highest, generally more than 40%, which is the most favorable segment for fracturing. The correlation coefficient between the interpretation data of CMR (combinable nuclear magnetic resonance) logging and the result of laboratory porosity test is 0.97, which can effectively and accurately evaluate the reservoir porosity. The evaluation results show that the porosity of the lower member of Shuijingtuo Formation is generally greater than 3%, while that of the upper member is generally less than 3%. The lower segment is with the relative optimal physical conditions. There is a good correlation between the acoustic logging data and the gas bearing content testing results. A gas bearing content evaluation model is established. The results show that the gas bearing content of the lower 20 m shale is generally more than 2%, indicating that the lower part is a shale gas enrichment segment. Mechanical parameters such as Young modulus, Poisson ratio and brittleness index of shale reservoir are evaluated by using the logging data of P-wave time difference and S-wave time difference. The continuous 15 m shale at the lower part is with the relatively optimal low Poisson ratio, high Young modulus and high brittleness index, developing the optimum brittle condition. Based on the evaluation and classification of above parameters, the shale is divided into three types. The Type Ⅰ is the optimal, mainly located at the bottom. Its thickness is 8.5 m in total. The Type Ⅱ mainly develops at the middle part. The Type Ⅲ is the worst, mainly at the upper part.
This study used a range of integrated and complementary experiments to examine pore-structure, fluid-shale wetting characteristics, sample size-dependent porosity towards different fluids, and imbibition behavior, as well as the relationships between these properties and the mineralogy of Silurian mudstones in the Central Taurides of Turkey. Working with different sample-sizes, the experiments consisted of helium pycnometry, low-pressure nitrogen physisorption isotherm, mercury intrusion porosimetry, fluid immersion porosimetry, liquid displacement, fluid droplet wettability and contact angle measurements, and spontaneous imbibition of fluids; four fluids with different hydrophilicity were used to assess the characteristics of fluid-shale interaction and its influence on pore-structure. Results show that studied mudstones can be grouped into three rock types: siliceous, carbonate-dominated, and mixed mudstones. Siliceous and mixed mudstones have higher porosities, pore-throat diameters, surface areas and tortuosities than the carbonate-dominated mudstones, regardless of sample sizes and fluids used. With low permeabilities and medium pore-throat sizes for the siliceous and mixed mudstones, the wettability and imbibition results show that these mudstones are both oil-wet and moderately-to-high water-wet. In contrast, the carbonate-dominated mudstones exhibit oil-wet characteristics. These results indicate that studied siliceous and mixed mudstones in the Central Taurides seem to have appropriate petrophysical properties in the context of reservoir quality.
It is of great significance to study the spatial distribution patterns and petrophysical complexity of volcanic vesicles which determine whether the reservoir spaces of the volcanic rocks can accumulate oil and gas and enrich high yields or not. In this paper, the digital images of three different textures of vesicular andesite samples, including spherical vesicular andesite, shear deformation vesicular andesite, and secondary filling vesicular andesite, are obtained by microscopic morphology X-CT imaging technology. The spatial micro-vesicle heterogeneity of vesicular andesite samples with different textures is quantitatively analyzed by fractal and multifractal methods such as box-counting dimension and the moment method. It is found that the shear stress weakens the spatial homogeneity since vesicles rupture are accelerated, elongated directionally, and connected with one another under the strain; the secondary filling breaks the vesicles, which significantly enhances the spatial heterogeneity. In addition, shear stress and secondary filling increase the complexity of vesicle microstructures characterized by different fractal and multifractal parameters. These conclusions will provide important theoretical and practical insights into understanding the degassing of volcanic rocks and prediction of high-quality volcanic reservoirs.
We present lithofacies classifications for a tight gas sandstone reservoir by analyzing hierarchies of heterogeneities. We use principal component analysis (PCA) to overcome the two level of heterogeneities, which results in a better lithofacies classification than the traditional cutoff method. The classical volumetric method is used for estimating oil/gas in-place resources in the petroleum industry since its inception is not accurate because it ignores the heterogeneities of and correlation between the petrophysical properties. We present the importance and methods of accounting for the heterogeneities of and correlation between petrophysical properties for more accurate hydrocarbon volumetric estimations. We also demonstrate the impacts of modeling the heterogeneities and correlation in porosity and hydrocarbon saturation for hydrocarbon volumetric estimations with a tight sandstone gas reservoir. Furthermore, geoscientists have traditionally considered that small-scale heterogeneities only impact subsurface fluid flow, but not impact the hydrocarbon resource volumetric estimation. We show the importance of modeling small-scale heterogeneities using fine cell size in reservoir modeling of unconventional resources for accurate resource assessment.
The microscopic pore structure of sand-conglomerate rocks plays a decisive role in its exploration and development of such reservoirs. Due to complex gravels-cements configurations and resultant high heterogeneity in sand-conglomerate rocks, the conventional fractal dimensions are inadequate to fully characterize the pore space. Based on the Pia Intermingled Fractal Units (IFU) model, this paper presents a new variable-ratio factor IFU model, which takes tortuosity and boundary layer thickness into consideration, to characterize the Triassic Karamay Formation conglomerate reservoirs in the Mahu region of the Junggar Basin, Northwest China. The modified model has a more powerful and flexible ability to simulate pore structures of porous media, and the simulation results are closer to the real conditions of pore space in low-porosity and low-permeability reservoirs than the conventional Pia IFU model. The geometric construction of the model is simplified to allow for an easing of computation. Porosity and spectral distribution of pore diameter, constructed using the modified model, are generally consistent with actual core data. Also, the model-computed permeability correlates well with experimental results, with a relative error of less than 15%. The modified IFU model performs well in quantitatively characterizing the heterogeneity of sand-conglomerate pore structures, and provides a methodology for the study of other similar types of heterogeneous reservoirs.
A reliable and effective model for reservoir physical property prediction is a key to reservoir characterization and management. At present, using well logging data to estimate reservoir physical parameters is an important means for reservoir evaluation. Based on the characteristics of large quantity and complexity of estimating process, we have attempted to design a nonlinear back propagation neural network model optimized by genetic algorithm (BPNNGA) for reservoir porosity prediction. This model is with the advantages of self-learning and self-adaption of back propagation neural network (BPNN), structural parameters optimizing and global searching optimal solution of genetic algorithm (GA). The model is applied to the Chang 8 oil group tight sandstone of Yanchang Formation in southwestern Ordos Basin. According to the correlations between well logging data and measured core porosity data, 5 well logging curves (gamma ray, deep induction, density, acoustic, and compensated neutron) are selected as the input neurons while the measured core porosity is selected as the output neurons. The number of hidden layer neurons is defined as 20 by the method of multiple calibrating optimizations. Modeling results demonstrate that the average relative error of the model output is 10.77%, indicating the excellent predicting effect of the model. The predicting results of the model are compared with the predicting results of conventional multivariate stepwise regression algorithm, and BPNN model. The average relative errors of the above models are 12.83%, 12.9%, and 13.47%, respectively. Results show that the predicting results of the BPNNGA model are more accurate than that of the other two, and BPNNGA is a more applicable method to estimate the reservoir porosity parameters in the study area.
Seismic and rock physics play important roles in gas hydrate exploration and production. To provide a clear cognition of the applications of geophysical methods on gas hydrate, this work presents a review of the seismic techniques, rock physics models, and production methods in gas hydrate exploration and exploitation. We first summarize the commonly used seismic techniques in identifying the gas hydrate formations and analyze the limitations and challenges of these techniques. Then, we outline the rock physics models linking the micro-scale physical properties and macro-scale seismic velocities of gas hydrate sediments, and generalize the common workflow, showing the frequently-used procedures of building models with detailed analysis of the potential uncertainties. Afterwards, we summarize the production techniques of gas hydrate and point out the problems regarding the petrophysical basis and abnormal seismic responses. In the end, considering the geological and engineering problems, we come up with several aspects of using geophysical techniques to solve the problems in gas hydrate exploration and production, hopefully to provide some important clues for future studies of gas hydrate.
Fluid mobility has been important topic for unconventional reservoir evaluation. The tight sandstones in Chang 7 Member of the Ordos Basin has been selected to investigate the fluid mobility based on the application of core flooding-NMR combined method and core centrifugation-NMR combined method, and the porous structure is studied using optical microscope, field emission scanning electron microscope (FE-SEM), CT and mercury injection. Our results include: (ⅰ) Feldspar-rock fragments dissolution pores, calcite dissolution pores, clay mineral dissolution pores, intergranular dissolution expansion pores, inter-granular pores, intra-kaolinite pores, and intra-illite/smectite mixed layer pores are developed in Chang 7 tight sandstones; 3D CT pore structure shows that the pore connectivity is positively related to physical properties, and the overall storage space is connected by the throat with diameter between 0.2 and 0.3 μm. The percentage of storage space connected by throats with diameter less than 100 nm can reach more than 35%. (ⅱ) Movable fluid saturation of Chang 7 tight sandstones is between 10% and 70%, and movable oil saturation is between 10% and 50%. Movable fluid saturation may cause misunderstanding when used to evaluate fluid mobility, so it is recommended to use movable fluid porosity in the evaluation of fluid mobility. The porosity ranging from 5% to 8% is the inflection point of the fluidity and pore structure. For samples with porosity less than 8%, the movable fluid porosity is generally less than 5%. Moreover, the movable fluid is mainly concentrated in the storage space with a throat diameter of 0.1 to 1 μm. For samples with porosity greater than 8%, the porosity of the movable fluid is more than 5%, and the movable fluid is mainly concentrated in the storage space with a throat diameter of 0.2 to 2 μm. (ⅲ) The movable fluid saturation measured by core flooding-NMR combined method is generally higher than that measured by core centrifugation-NMR combined method. The former can evaluate the mobility of the oil-water two-phase fluid in samples, while the latter can better reflect the pore structure and directly evaluate the movable fluid in the pore system controlled by different throat diameters. All these results will provide valuable reference for fluid mobility evaluation in tight reservoirs.
Investigating the variation of water content in shale reservoir is important to understand shale gas enrichment and evaluate shale gas resource potential. Low water saturation is widely spread in Longmaxi marine organic-rich shale. To illustrate the formation mechanism of low water saturation, this paper analyzed water saturation of Longmaxi shale reservoir, restored the history of natural gas carrying water capacity combining homogenization temperature and trapping pressure of fluid inclusion with simulated thermal history, and established a model to explain pore water displaced by natural gas during the thermal evolution. Results show that the gas-rich Longmaxi shale reservoir is characterized by low water saturation with measured values ranging from 9.81% to 48.21% and an average value of 28.22%. TOC in high-mature to over-high-mature Longmaxi organic-rich shale is negatively correlated with water saturation, indicating that well-connected organic pores are not available for water. However, quartz and clay mineral content are positively correlated with water saturation, which suggests that inorganic-matter-hosted pores are the main storage space for water formation. The water carrying capacity of natural gas varies as a function of gas generation and expulsion history, which displaces bound and movable water in organic pores that are part of bound and movable water from inorganic pores. The process can be divided into two phases. The first phase occurred due to the kerogen degradation into gas at Ro of 1.2%-1.6% with a water carrying capacity of natural gas ranging from 5 632.57-7 838.73 g/km3. The second phase occurred during the crude oil cracking into gas at Ro>1.6% with a water carrying capacity of natural gas ranging from 10 620.04 and 19 480.18 g/km3. The water displacement associated with natural gas generation and migration resulted in gas filling organic pores and gas-water coexisting in the brittle-mineral-hosted pores and clay-mineral-hosted pores.
Reconstruction of the diagenetic evolution of reservoirs is one of the most significant tasks in oil and gas exploration and development. Assessing the accurate timing of diagenetic events is critical to better understand the process of reservoir evolution, but the isotope dating of diagenetic events is technically challenging. This paper uses three case studies in the sedimentary basins in China to demonstrate the promising application of recently developed LA-(MC)-ICPMS in-situ U-Pb geochronology. Our results show that the new U-Pb dating method provides a reliable and efficient chronological approach to determine the absolute ages of diagenetic events. For example, the U-Pb age data of the Cambrian carbonate reservoir in the Tarim Basin reveals three diagenetic events at 526±14, 515±21, and 481±4.6 Ma, respectively. It is worth noting that microscopic observations are particularly important for improving the success rate of U-Pb dating. In addition, the recent progress and future prospects in the in-situ U-Pb dating method are also discussed in this study, suggesting that this method is currently hindered by the lack of international carbonate standards for data correction.
Carbonates are considered to be important hosts of oxidized carbon during subduction processes. Here we investigate the redox interactions between dolomite and metallic iron in laser-heated diamond anvil cells up to ~20 GPa. The identification of recovered samples via in-situ synchrotron X-ray diffraction and ex-situ Raman spectroscopy shows that the reaction occurs with the formation of ferropericlase, graphite and hexagonal diamond, while CaCO3 remains stable. The experimental results indicate dolomite and metallic iron phases cannot coexist and demonstrate a possible formation mechanism of ultradeep diamonds via redox reaction between dolomite and iron under the mantle transition zone conditions. The results are significant for understanding carbon transportation during subduction processes and have further implications to the processes in the more complex systems regarding to carbonate-silicate-metal phase relations.
In recent years, significant progress in shale gas exploration has been achieved in the Upper Ordovician (Wufeng Formation)-Lower Silurian (Longmaxi Formation) shales in the Upper Yangtze area, South China. Although many studies have been carried out on the Upper Ordovician-Lower Silurian shales, the controlling factors causing organic matter accumulation of these shales remain controversial. This study uses trace-element geochemistry and sedimentological methods to evaluate terrigenous input, redox conditions and primary productivity to explore the mechanisms of organic matter accumulation. The variation of terrigenous fraction elements (Al, Th and Sc) concentrations reflect a mixed influence of sea-level change and weathering. The sea-level of the Upper Yangtze Sea went through two cycles of transgression to regression during the Ordovician-Silurian transition. The Linxiang Formation, Kuanyinchiao Bed and the upper part of Longmaxi Formation developed during the periods of regression, whereas the Wufeng Formation and the lower part of the Longmaxi Formation developed during the periods of transgression. The paleo-productivity indexes of TOC content, ratios of Ba/Al and P/Al, and redox conditions proxies of Mo concentration, ratios of U/Th and V/Cr generally display similar variation patterns with respect to the sea-level changes. High TOC contents and Ba/Al and P/Al ratios indicate the paleo-productivity was high on the sea surface, as shown by relatively good positive correlations between Th vs. TOC, and Sc vs. TOC. This indicates that the paleo-productivity was controlled by the nutrients input through weathering. The good positive correlations between redox conditions indexes (U/Th and V/Cr ratios) with TOC content reflects reductive preservation conditions (anoxic to euxinic), thus implying they were an important controlling factor for organic matter accumulation. Nevertheless, redox conditions were closely associated with sea level change and organic matter decomposition. Therefore, the sea-level change and weathering were the primary controlling factors for organic matter enrichment across the Ordovician to Silurian transition.
Sandy-conglomerate reservoir has gradually become a major target of oil and gas exploration. Complex diagenetic process and diagenetic fluid play a significant role in affecting reservoir heterogeneity. Carbonate cements form at various stages of the diagenesis process and record various geological fluid information. Recently, one-billion-ton sandy conglomerate oil field was exposed in Triassic Baikouquan Formation, Mahu sag, Junggar Basin. Therefore, an integrated study applying casting thin sections, cathodeluminescence, fluorescence, carbon and oxygen stable isotopes, electronic probe microanalysis and aqueous fluid inclusions measurements was performed in order to identify the types of carbonate mineral and its representative diagenetic environment and discuss the influences of different CO2 injections on reservoir quality. The main findings are as follows: The reservoir is mainly composed of 70.33% conglomerate and 16.06% coarse-grained sandstone. They are characterized by low compositional maturity and abundant lithic debris. Four types carbonate cements are identified according to the petrological and geochemical characteristics, including two types of Mn-rich calcite, ferroan calcite, siderite and dawsonite. They display an unusual broad spectrum of δ13C values (-54.99‰ to +8.8‰), suggesting both organic and inorganic CO2 injections. The δ13C values of siderite are close to 0, and its formation is related to meteoric water. The δ13C values of ferroan calcite and the occurrence of dawsonite indicate the trace of inorganic mantle-derived magmatic fluids. The δ13C values and trace elements of Mn-rich calcite record the information of hydrocarbon-bearing fluids. The fluid inclusions measurement data and reservoir properties and oil-test data show that the oil content of reservoir is not only affected by the formation time of different cements, but also by the relative content of dissolution and cementation. For these reservoirs altered by carbonate cements, it does not cause poor oil-bearing due to blockage of secondary minerals.
The burial depth of the metamorphic buried hill of the Bozhong sag is more than 4 500 m, however, the controlling factors of the reservoirs are not clear. Based on cores and sidewall cores obtained from 15 wells, this paper describes the reservoir characteristics and discussed their controlling factors. The metamorphic basement of the Bozhong sag consists of metamorphic granite, migmatitic granite and gneiss. These felsic rocks are more likely to develop fractures, thereby improving the reservoir properties. The Indosinian, Yanshanian and Himalayan tectonic events greatly reformed the Bozhong 19-6 metamorphic buried hill, forming a large scale fracture system. Weathering and deep thermal fluid contributed to the development of dissolved pores of the reservoirs. In general, controlled by lithology, tectonics, weathering and deep thermal fluid, the reservoir pattern of the metamorphic buried hill of the Bozhong 19-6 structure was established.
Natural fractures, as the main flow channels and important storage spaces, have significant effects on the migration, distribution, and accumulation of tight oil. According to outcrop, core, formation micro image (FMI), cast-thin-section, and scanning electron microscopy data from the tight reservoir within the Permian Lucaogou Formation of the Junggar Basin, tectonic fractures are prevalent in this formation mainly on micro to large scale. There are two types of fractures worth noticing: diagenetic fractures and overpressure-related fractures, primarily at micro to medium scale. The diagenetic fractures consist of bedding fractures, stylolites, intragranular fractures, grain-boundary fractures, and diagenetic shrinkage fractures. Through FMI interpretation and Monte Carlo method evaluation, the macro-fractures could be considered as migration channels, and the micro-fractures as larger pore throats that function as storage spaces. The bedding fractures formed earlier than all tectonic fractures, while the overpressure-related fractures formed in the Middle and Late Jurassic. The bedding fractures and stylolites function as the primary channels for horizontal migration of tight oil. The tectonic fractures can provide vertical migration channels and reservoir spaces for tight oil, and readjust the tight oil distribution. The overpressure-related fractures are fully filled with calcite, and hence, have little effect on hydrocarbon migration and storage capacity. The data on tight oil production shows that the density and aperture of fractures jointly determine the productivity of a tight reservoir.
Due to the existence of water content in shale reservoir, it is quite meaningful to clarify the effect of water content on the methane adsorption capacity (MAC) of shale. However, the role of spatial configuration relationship between organic matter (OM) and clay minerals in the MAC reduction process is still unclear. The Silurian Longmaxi Formation shale samples from the Southern Sichuan Basin in China were prepared at five relative humidity (RH) conditions (0%, 16%, 41%, 76%, 99%) and the methane adsorption experiments were conducted on these water-bearing shale samples to clarify the MAC reduction process considering the spatial configuration relationship between clay minerals and OM and establish the empirical model to fit the stages. Total organic carbon (TOC) content and mineral compositions were analyzed and the pore structures of these shale samples were characterized by field-emission scanning electron microscopy (FE-SEM), N2 adsorption and high-pressure mercury intrusion porosimetry (HPMIP). The results showed that the MAC reduction of clay minerals in OM occurred at different RH conditions from that of clay minerals outside OM. Furthermore, the amount of MAC reduction of shale samples prepared at the same RH condition was negatively related with clay content, which indicated the protection role of clay minerals for the MAC of water-bearing shale samples. The MAC reduction process was generally divided into three stages for siliceous and clayey shale samples. And the MAC of OM started to decline during stage (1) for calcareous shale sample mainly because water could enter OM pores more smoothly through hydrophobic pathway provided by carbonate minerals than through hydrophilic clay mineral pores. Overall, this study will contribute to improving the evaluation method of shale gas reserve.
Unconventional volcanic reservoir is different from conventional reservoir in reservoir space, diagenesis, pore formation and evolution. The Carboniferous volcanic reservoir was selected in Junggar Basin, Northwest China because based on sediment/rock cores and outcrop data, diagenesis and pore evolution were studied by elemental measurements, thin section observations, and diagenetic analyses. These analyses shows that the reservoir lithology is predominantly intermediate-basic volcanic, and the reservoir storage space is composed mainly of secondary dissolved pores and fractures. The reservoir displays great heterogeneity, and has experienced a great variety of diagenetic alteration during various diagenetic stages including: (1) eruption fragmentation, crystallization differentiation and condensing consolidation at consolidated diagenetic stage; (2) metasomatic alteration, filling, weathering and leaching, dissolution by formation fluids and tectonism at the epigenetic modifications stage. The formation and evolutionary process of the pores is extremely complicated. The primary pores were formed during the consolidated diagenetic stage, and laid a foundation for the late development and alteration of effective reservoir. During the epigenetic modifications stage secondary reservoir storage space was developed via the formation of secondary pores and the development of fractures through weathering and leaching, dissolution by formation fluids and tectonism.
The Carboniferous volcanic reservoirs in Junggar Basin contain rich hydrocarbon resources, implying a great exploration potential, so that they have become a key replacement target for "three-dimensional exploration". The study on the Carboniferous volcanic reservoirs and their hydrocarbon accumulation elements is significant for clarifying the orientation for exploration. In this paper, based on 37 reserves reports and 3 200 reservoir test data, the Carboniferous volcanic reservoirs in Junggar Basin were discussed from the prospective of lithology and lithofacies, physical properties, reservoir types, main controls on hydrocarbon accumulation, and hydrocarbon accumulation patterns. It is found that the Carboniferous in the basin is mostly in the multi-island ocean-volcanic island arc structural-sedimentary environment, so it is geologically eligible for forming in-situ volcanic reservoirs. The volcanic rocks are: (1) mostly distributed along deep and large faults, with the lithology and lithofacies controlled by volcanic architectures; (2) dominantly lava, followed by volcaniclastic lava and volcaniclastic rock; (3) distributed in the periphery of hydrocarbon-generating sag and within the source rocks horizontally, and concentrated in the weathering crust at the top longitudinally, possibly leading to reworked weathering crust reservoir; and (4) liable to form inner reservoirs. The volcanic reservoirs can be concluded into four hydrocarbon accumulation patterns, i.e., self-generating & self-storing in paleo-uplift and vertical migration, self-generating & self-storing in paleo-uplift and lateral migration, young-generating & old-storing in fault zone and vertical migration, and young-generating & old-storing in paleo-uplift and lateral migration. Future exploration will focus on the effective source rock development and hydrocarbon supply zones and the self- generating & self-storing and young-generating & old-storing patterns. The exploration prospects are determined to be the Ludong-Wucaiwan-Baijiahai slope belt and the southern slope belt of the Shaqi uplift (self-generating & self-storing pattern) in eastern Junggar, and the fault and nasal arch zone at the northwestern margin and the nasal arch zone (deep and large structure) in the Luxi area (young-generating & old-storing pattern) in western Junggar.
Due to the complicated lithology in the ES3 Member of the Shahejie Formation in the Shulu sag, Jizhong depression, it is difficult to classify the rock types and characterize the reservoirs at the marl intervals. In this paper, a four-element classification method has been proposed, and seven rock types have been identified by analyzing the mineral composition. The primary rock types are medium-high organic carbonate rocks and medium-high organic shaly-siliceous carbonate rocks. With the methods of field emission scanning electron microscopy, high-pressure mercury intrusion, nitrogen adsorption, and nano-CT, four types of reservoir spaces have been identified, including intra-granular pores, inter-granular pores (inter-crystalline pores), organic pores, and micro-fractures. By combining the method of high-pressure mercury intrusion with the method of the nitrogen adsorption, the porosity of the marl has been measured, ranging from 0.73% to 5.39%. The distribution of the pore sizes is bimodal, and the pore types are dominated by micron pores. Through this study, it has been concluded that the sag area to the east of Well ST1H is the favorable area for the development of self-sourced and self-reservoired shale oil. According to the results of geochemical and reservoir analysis, the Ⅲ Oil Group may have sweet spot layers.
This study examines the characteristics and pore evolution of the Baikouquan conglomerate reservoir in the Mahu sag of the Junggar Basin from original sedimentation and diagenesis. Analysis is based on core observation, thin section, X-ray diffraction, cathodoluminescence and image analysis, and combined with physical property and well log data. The results show that conglomerate reservoir in the Baikouquan Formation can be divided into three lithofacies types: Type Ⅰ is argillaceous filling conglomerate facies, in which cementation and dissolution are not developed, and the interstitial material is mainly argillaceous; Type Ⅱ is tuffaceous filling in fine conglomerate facies, in which volcanic rock debris, illite and dissolution are developed; Type Ⅲ is sandstone filling conglomerate facies, in which cementation and dissolution are developed. The reservoir undergoes complex diagenesis, and the diagenetic sequence is: compaction→early chlorite film→early calcite cementation→detritus, feldspar and tuffaceous dissolution→quartz secondary enlargement→late calcite cementation→oil invasion→forming illite. Quantitative study of pore evolution shows that dissolution and calcite cementation are relatively developed in lithofacies Type Ⅲ, and that compaction has a great influence on lithofacies Type Ⅰ and Ⅱ. According to comprehensive evaluation of lithofacies, diagenesis and pore structure characteristics, the reservoir space type is mainly the dissolution pore. It is mainly primarily mainly composed of lithofacies Type Ⅲ, thickness of the gravel body is more than 25 m, porosity is generally more than 12%, which represents favorable conditions for the distribution of favorable reservoir.
The Lenghu area is one of the most crucial tectonic belts for oil and gas exploration in the Qaidam Basin. However, reservoir distribution and the factors controlling petroleum accumulation in this area have not been studied in detail. In this paper, the structural characteristics and controlling factors of oil and gas accumulation in the Lenghu belt are investigated based on seismic profiles combined with drilling logs and microphotographs data. Results indicate that the Lenghu belt has thick source rocks and has preserved hydrocarbon generation conditions. Moreover, structural characteristics and lithology are the key factors controlling the reservoir distribution. The production of oil and gas layers are mainly distributed in high structural points and weak stress zones. The fracture zones and the weak stress zones are the potential places for the distribution of oil and gas reservoirs.
Hydrocarbon source potential of the Paleogene Pabdeh Formation was studied by means of organic geochemistry and distribution of calcareous nannofossils. Based on the results, an Eocene-aged organic matter (OM)-rich interval was identified and traced across different parts of the North Dezful zone and partly Abadan Plain. In order to characterize the OM quality and richness of the studied intervals, Rock-Eval pyrolysis and nannofossils evaluation were performed, and the geochemical data collected along selected wells were correlated to capture the variations of thickness and source potential of the OM-rich interval. Accordingly, remarkable variations were identified within the depth ranges of 2 480-2 552 m and also 2 200-2 210 m, which were attributed to the maximum increase in the rate of growth R-selected species. This increase in the productivity rate was found to be well correlated to high Rock-Eval total organic carbon (TOC) and hydrogen index (HI) values. Given that the maturity of Pabdeh Formation in the studied area was found to have reached the oil window, we expect significant hydrocarbon generation (Type Ⅱ kerogen), making the play economically highly promising.
The Cenozoic basalts exposed in Bo Phloi Gem Field, Kanchanaburi Province, western Thailand are a host to different gem materials (e.g., sapphire, black spinel, black pyroxene and zircon) as well as other xenocrysts and xenoliths from the deep-seated formations onto the earth surface. However, only felsic xenoliths have never been investigated and reported in detail though they are in fact significant evidence of ancient tectonic processes of this area. In this study, the felsic xenoliths were sampled and classified, on the basis of petrochemistry, into granite, syenogranite, and syenite. However, they contain similar mineral assemblages including essentials of quartz, K-feldspar, and plagioclase with different proportions and accessories of biotite, zircon, and opaque minerals. Moreover, large phenocrysts of K-feldspar and plagioclase commonly present as a primary texture which are frequently corroded and replaced by 'sieved texture' with secondary cumulative fringe of tiny feldspar and quartz. These secondary textures clearly indicate quenching after re-heating during transportation by basaltic magma. Geochemical analyses indicate that the alkaline and peraluminous magma show enrichment of Rb and depletion of Ba, Nb, Ta, Ti with steep slope of LREE/HREE enrichment patterns. These evidences suggest low-degree partial melting of crustal materials related to the collisional S-type granite magmatism. In addition, U-Pb dating of zircon from a felsic xenolith yields 211.6±1.3 Ma comparable to the Late Triassic magmatism of the central belt granite in this region which is resulted from the collision between Sibumasu and Indochina terranes.