In 2018, based on a detailed characterization of paleogeomorphology, the sedimentary facies of the upper Wuerhe formation on the western slope of Shawan sag, Junggar basin, were identified, and a breakthrough was achieved by deploying Well ST 1 according to the hydrocarbon accumulation model of “trough-controlled sandbody, facies-controlled reservoir”. However, due to insufficient research on sedimentary facies and reservoirs, the reservoirs encountered by Well ST 1 didn’t meet the expectation in scale, with the hydrocarbon accumulation model to be clarified. In this paper, using the seismic, logging, core, and geochemical data, the sedimentary facies and reservoirs of the upper Wuerhe formation on the western slope of the Shawan sag were systematically investigated. The results show that two sedimentary systems, i.e., Xiaoguai fan and Shamenzi fan, are developed in the Shawan sag. Shamenzi fan which is larger in scale is characterized by retrogradational fan delta sedimentary facies. The upper Wuerhe formation (P3w) can be divided into three members such as P3w1, P3w2 and P3w3 from bottom to top. The thin sand layers in P3w2, and the glutenites in the lower part of the upper P3w1 and the upper part of the lower P3w1 are the main reservoirs. Dual-porosity reservoirs are developed in the upper Wuerhe formation, and the faults connected to source rocks provide dominant pathways for oil and gas migration. A hydrocarbon accumulation model of “fault-connected source, fan-controlled reservoir, and fracture-controlled production” was established. Accordingly, fault-lithologic reservoirs and fault-stratigraphic reservoirs have been discovered on the western slope of the Shawan sag, expanding the exploration area in the upper Wuerhe formation.
The Shiqiantan sag in the eastern Junggar basin is a residual marine sag. In recent years, high-yield natural gas have been obtained from many wells in the Shiqiantan formation, and oil and gas shows have been observed in different strata across the sag, indicating its excellent exploration potential and characteristics as a total petroleum system. Based on seismic, drilling, logging, and organic geochemical data, the formation and evolution of the Shiqiantan sag, the conditions for the formation of the total petroleum system, and the models of hydrocarbon accumulation are studied. The results show that during the Late Carboniferous the north Tianshan oceanic crust subduction and seawater intrusion in the region led to the development of terrigenous, marine, medium- to high-quality source rocks which are now in the mature- to high-mature stage. The reservoir contains volcanic rocks in the Carboniferous strata, marine clastic rocks in the Shiqiantan formation, and continental clastic rocks in the Permian Jingou formation, in all of which hydrocarbons were accumulated. Controlled by the hydrocarbon generation and evolution in the source rocks of the Shiqiantan formation and the characteristics of multiple types of reservoirs, a distribution pattern of shale gas reservoir in the sag-tight oil and gas reservoir in the slope-conventional oil and gas reservoir in the high position is formed, showing a total petroleum system featured with orderly symbiosis of unconventional and conventional oil and gas reservoirs. According to the theory of total petroleum system, the exploration in the Shiqiantan sag should focus on tight oil and gas reservoirs in the near-source slope area, structural-lithological oil and gas reservoirs and volcanic weathering-crust oil and gas reservoirs in the above-source fault-terrace area and structural high, and marine shale gas reservoirs within the source. The Carboniferous near-source favorable lithofacies belts, piedmont thrust fault-concealed structures, intra-basin palaeouplifts, and slope areas are favorable exploration zones in northern Xinjiang. Specifically, exploration efforts should be made towards shale oil and gas reservoirs within the sag, tight sandstone oil and gas reservoirs around the sag, conventional oil and gas reservoirs in the structural highs, and volcanic weathering-crust oil and gas reservoirs in uplifted areas.
The confirmation of 100-million-ton reserves in the Permian upper Wuerhe formation in the Kangtan-1 well area of Fukang sag, Junggar basin, demonstrates the excellent hydrocarbon accumulation conditions and huge exploration potential of the deep layers in the sag. Summarizing the exploration experience and theoretical understanding of the upper Wuerhe formation in the Fukang sag will be significant to guide the exploration of clastic reservoirs in other hydrocarbon-rich sags. Using the data of drilling, reservoir rock thin section, porosity-permeability analysis and formation testing, a systematic analysis was conducted on the exploration breakthrough of the upper Wuerhe formation in the Fukang sag. It is indicated that the oil and gas in the uplift and slope zones around the Fukang sag are mainly products of source rocks in the early maturity stage, and the hydrocarbons generated in the high maturity stage of source rocks are mainly found in the sag area. Controlled by the paleogeomorphology during deposition, retrogradational sand bodies in lowstand systems tract （LST） were developed in the upper Wuerhe formation in the Fukang sag, forming superimposed continuous large-scale reservoirs in the paleo-trough area. Overpressure is commonly found in the sag, which is conducive to the preservation of primary pores in deeply buried sandstones and also to the formation of microfractures, enhancing the permeability of reservoirs and making the deep reservoirs more effective. The upper Wuerhe formation in the Fukang sag has large exploration potential for achieving reserves increment due to the late-stage charging of hydrocarbons generated from highly mature sources rocks in the Lucaogou formation, the large-scale retrograditional sedimentation, and the pore preservation and permeability increasement caused by overpressure.
Through thin section and scanning electron microscopy （SEM） observations and energy spectrum analysis, the types and characteristics of zeolite cements in the Permian sandy conglomerate reservoirs in the Shawan sag of Junggar basin were identified, and the mechanism of differential bonding between zeolite cements and clastic particles was clarified. The results show that in the Upper Permian upper Wuerhe reservoirs, the plastic deformation of rock fragments and alkaline formation water result in strong bonding between laumontites and clastic particles and in the Lower Permian Fengcheng reservoirs, laumontites are lowly bonded with clastic particles under the conditions of abnormally high pressure, and acidic fluids, while heulandites are highly bonded with clastic particles due to their crystal characteristics. The differential bonding between zeolite cements and clastic particles in the upper Wuerhe and Fengcheng reservoirs are mainly related to rock composition, abnormal pressure, mineral type, crystal structure, and the degree of late diagenetic fluid alteration.
In order to understand the development characteristics and formation mechanism of reservoir space in the crushed zone of a strike-slip fault, based on the field outcrops, remote sensing images, and core testing data, the reservoir space in the northern Yujiang strike-slip fault zone was identified and quantified, and its main controlling factors were discussed. The results show that the crushed zone of the northern Yujiang strike-slip fault zone can be divided into a northern tenso-shear segment and a southern compresso-shear segment in a plane view. The two segments are different in the reservoir space development characteristics. The tenso-shear segment has larger fracture aperture, while the compresso-shear segment has larger fracture length, fracture density, fractured area, and cave area. Overall, the compresso-shear segment has larger reservoir space. The tectonic stress of the strike-slip fault zone is the external factor determining the development of dominant reservoir space, while the thickness and mineral composition of rocks are the internal factors controlling reservoir space development. The carbonate rocks with a thickness greater than 1 m and a calcium carbonate content of less than 70% can be reworked by compresso-shear process to form favorable areas for the development of fractured-vuggy reservoirs.
The Cretaceous Bashijiqike formation in the Kelasu structural belt in the Kuqa depression of Tarim basin hosts a number of high- and steady-yield subsalt gas reservoirs in ultra-deep，high-temperature，and overpressure environment. For these subsalt tight sandstone reservoirs，the higher the porosity，the higher the salt content and the lower the apparent resistivity. The distribution of salt in the reservoirs not only significantly affects fluid identification but also has a noticeable impact on the reservoir physical properties. The distribution of salt in the subsalt reservoirs in the Bashijiqike formation were systematically analyzed based on the data of cores，cast thin sections，scanning electron microscopy，salt content，and conventional logs. According to the differences in salt content，resistivity，and salt source，three distribution patterns of salt in subsalt reservoirs were proposed: top source，lateral source and local sealing. For the top and lateral source patterns，the reservoir resistivity is only affected by salt content. In the reservoirs with the top source pattern，the salt content shows a vertical zonality，and the reservoir resistivity increases as the salt content decreases. In the reservoirs with the lateral source pattern，the salt content shows a lateral zonation，and the reservoir resistivity shows a trend of high to low and then to high value from the edge of structural belt towards its center. In the reservoirs with the local sealing pattern，the resistivity is influenced jointly by stress and salt content，and changes greatly because the distribution of salt content is sporadic. According to well logging responses，the reservoir is divided into intervals for each pattern. In an ideal top source pattern，the reservoir comprises a salt interval，a mudstone barrier，an interval strongly affected by saturated salt，an interval strongly affected by unsaturated salt，a transition interval affected by unsaturated salt，and a salt-unaffected interval from top to bottom. In an ideal lateral source pattern，there are several intervals affected by oversaturated salt. In an ideal local sealing pattern，the reservoir includes a salt interval，a mudstone barrier，a salt-unaffected interval with strongly compressed stress，a salt-stress hybrid affected interval，and a salt-stress unaffected interval.
To determine hydrocarbon enrichment degree around the faults connecting oil and source rocks in petroliferous basins，based on the study of source rock-fault-caprock configuration，and the hydrocarbon accumulation mechanism，a method for predicting hydrocarbon accumulation period under source-fault-caprock configuration was established，which considers the activity period of the fault connecting oil and source rocks，the hydrocarbon expulsion period of source rock，and the formation period of mudstone caprock. The method was applied to predict the hydrocarbon accumulation period in the lower Sha 1 member within the Qikou sag of the Bohai Bay basin. The results show that during the deposition period of the Guantao formation-Minghuazhen formation，the source rock in Sha 3 member expelled hydrocarbons，the Nandagang fault was opened，and the regional mudstone caprock in the middle Sha 1 member was formed. The source rock，fault and caprock were configured well for a long period，which allowed the hydrocarbons expelled from the source rock in Sha 3 member to effectively accumulate in the lower Sha 1 member. The prediction results are consistent with the exploration results.
To find favorable areas for shale gas accumulation in the Wufeng formation-Longmaxi formation in the Luzhou area of the Sichuan basin，fluid inclusion detection，shale micropore observation，and gas bubble-pore evolution simulation were performed. On this basis，the tectonic burial process and the hydrocarbon generation and thermal evolution process in the Luzhou area were investigated，and the characteristics and patterns of shale gas accumulation in the Luzhou area were summarized. The results show that the Wufeng formation-Longmaxi formation in the Luzhou area has a set of thick organic-rich shales. During the Permian to Early Triassic，oil was generated from the shale which then experienced two tectonic uplift events during the Middle Triassic and the Yanshanian-Himalayan movement. The gentle uplifting of the formation in the Middle Triassic did not induce extensive hydrocarbon loss，while the uplifting during the Yanshanian-Himalayan movement was later than that of the structure in the southeastern part of Sichuan basin，with a small magnitude，which was favorable for shale gas preservation. The organic pores in the shales were developed as a result of the fact that the uplifting with short duration and low intensity in the Middle Triassic did not cause massive hydrocarbon expulsion，leaving a large quantity of liquid hydrocarbons in the reservoirs and allowing well preservation of organic pores during the Late Triassic to Middle Cretaceous，when liquid hydrocarbons were cracked to gas along with deep burial，and the strata were universally under overpressure. Although the Triassic uplifting in the Luzhou area was short-lived and of low intensity，the simulation results suggest that it led to crude oil thickening and gas pore formation，which was beneficial for shale gas accumulation. The uplifting in the Indosinian period resulted in crude oil thickening，facilitating shale gas accumulation. The late strata uplifting together with a short period of shale gas loss，developed low-angle bedding fractures，and fewer vertical fractures all contribute to the formation of overpressured shale gas accumulation zones in the Luzhou area. The proposed patterns of shale gas accumulation in the Wufeng formation-Longmaxi formation in the Luzhou area are of great reference significance in guiding oil and gas exploration for similar reservoirs.
In order to clarify the main controlling factors of shale oil and gas enrichment，the degree and mechanisms of shale oil and gas enrichment in the Chang 7 member in southeastern Ordos basin were analyzed using the data of drilling，logging，and core. Desorbed shale gas content is positively correlated with the total organic carbon content (TOC) of source rocks，the organic matter content controls the total content of shale oil and gas，and abundant pores are developed in organic matter，and shale oil and gas exist in both adsorbed and free states in these organic pores. The pore structure and porosity of the reservoir affect the content and occurrence state of shale oil and gas. Adsorbed oil and gas mainly exist in micropores，while free oil and gas in mesopores and macropores. The content of free gas in mesopores is higher than that in macropores，and the larger the porosity，the higher the absolute content of oil and gas in shale. The configuration between sandstone interlayers and organic-rich shale controls the enrichment positions of shale oil and gas. Based on the distribution of siltstone，fine sandstone and shale in the reservoir，the shale oil and gas in Chang 7 member can be classified into two types：near-source and in-source. The in-source shale oil and gas can be further divided into hydrocarbons from sandstone interbedded with shale，shale intercalated with sandstone，and pure shale. Sand bodies underlying the organic-rich shale and lenticular sand bodies exhibit the best potential of oil and gas，followed by sand bodies overlying the organic-rich shale or those tongue-shaped or finger-shaped ones in contact with shale.
To clarify the geochemical characteristics and origin of the crude oil from the coal mine in Yan’an formation in Huangling-Tongchuan area，southeastern Ordos basin，a comparative study was conducted on the biomarker compositions and carbon isotope distribution of n-alkane monomers in extracts from crude oil，coal，and mudstone in the study area using gas chromatography，chromatography-mass spectrometry，and isotope mass spectrometry techniques. The oil from coal mine is characterized by equilibration of pristane and phytane，high sesquiterpene content，relatively high Ts/Tm and C29Ts/C29 norhopane ratios，relatively low ratios of C30 moretane/C30 hopance，C30 norhopane/C30 hopance，and 22S/(22S+22R) for C31 homohopane and C32 homohopane，“V”-shaped distribution of ααα-20R regular sterane，and relatively light carbon isotopic values of crude oil and n-alkane monomers. The extracts from the Jurassic coal-bearing source rocks exhibit high Pr/Ph ratio，low sesquiterpene content，low Ts/Tm and C29Ts/C29 norhopane ratios，relatively high ratios of C30 moretane/C30 hopance，C30 norhopane/C30 hopance，and high 22S/(22S+22R) values for C31 homohopane and C32 homohopane，inverted “L”-shaped distribution of ααα-20R regular sterane，and relatively heavy carbon isotopic values of crude oil and n-alkane monomers. The characteristics of crude oil significantly differ from those of the potential coal-bearing source rocks，which is consistent with the deep lacustrine source rocks and the generated hydrocarbons of Chang 7 member in the basin. The coal of the Jurassic Yan’an formation is at a low maturity stage，and it is incapable of expelling liquid hydrocarbons，since the generated liquid hydrocarbons cannot even fully meet its adsorption needs. The crude oils in the Cuijiagou Coal Mine in Tongchuan and the Diantou Coal Mine in Huangling are both originated from the source rocks of the underlying Chang 7 member.
Based on the seismic, geological, geochemical, and production testing data, the types and distribution patterns of the tight oil reservoirs in the first member of Yaojia formation (Yao 1 member) in the Gulong sag were analyzed, and then the controlling factors and models of hydrocarbon accumulation in these reservoirs were clarified. The results show that five types of tight oil reservoirs are developed in the Yao 1 member such as lenticular sandstone reservoir in the Gulong syncline, updipping pinch-out lithologic reservoir, fault-lithologic reservoir, fault-block reservoir, and fault-anticline reservoir at the top of the nose-like bulge. The formation of tight oil reservoirs is jointly controlled by source rock and overpressure distribution, traps, oil-source faults, and high-quality reservoir beds. The lacustrine mudstones in the first member of Qingshankou formation (Qing 1 member) serve as the material basis for tight oil reservoirs and also create abnormally-high pressure that drove oil charging into the Gulong syncline. Before extensive hydrocarbon accumulation, various traps had been formed, including structural traps and structural-lithological traps at high positions on both sides, which act as the tight oil migration destinations and favorable accumulation sites. The reversal-stage faults that opened during the main oil accumulation phase serve as the primary pathways for vertical oil migration, and high-quality distributary-channel reservoir beds are favorable for tight oil accumulation. The structural units are different in controlling factors and models of hydrocarbon accumulation. In the Gulong syncline, the hydrocarbon accumulation model is “driven by overpressure, vertical migration along faults, and enrichment in local sweet spots”. In the Xinzhan nose-like bulge, the hydrocarbon accumulation model is “first driven by overpressure then by buoyancy, vertical migration along faults, and accumulation in favorable traps”. In the Xinzhao slope, the hydrocarbon accumulation model is “driven by overpressure + buoyancy, fault-sandbody relay-migration, and accumulation in favorable reservoir beds”.
In the Tahe oilfield of the Tarim basin, the Middle-Lower Ordovician surface and subsurface karsts were diverse morphologically in the early Hercynian. There are abundant oil and gas resources in subsurface karst fracture-vug systems. Based on high-precision seismic data and drilling data, and by unifying the subsurface and surface water systems, the Middle-Lower Ordovician karst water system in the early Hercynian movement in the Tahe oilfield was constructed. The research results show that, in the early stage of the Hercynian movement in the Tahe oilfield, there developed four karst platforms in the Middle-Lower Ordovician, generally distributed in a step-like pattern with higher elevation in the east than in the west. The differential drainage and dissolution of karst water resulted in various hydromorphology, such as canyon, underground river, incised meandering river, and wide valley. The karst water system are mainly bounded by surface watershed, drainage baseline, stratigraphic lithology assemblage, fault, and weak dissolution zone. The karst water system in the Tahe oilfield can be divided into four relatively independent secondary karst water systems: plateau canyon water system, underground river canyon water system, incised meandering river water system, and wide valley water system. This classification of the hierarchical structure of the karst water system provides a geological basis for further understanding the karst fracture-vug system and karst fracture-vug unit in the Tahe oilfield.
Shallow-water delta reservoirs are developed in the Songliao basin, where the difficulties in reservoir prediction are restricting oil and gas exploration and development. Adhering to the idea of geology-seismology integration and based on high-resolution seismic survey and high-precision sequence stratigraphy, the Yaojia formation in the Xingxi area of the Songliao basin was investigated with respect to sequence stratigraphy, geophysical responses of reservoirs, and spatio-temporal evolution of sand body dispersion system by using the techniques such as 90° seismic phase conversion, forward modeling, and seismic attribute analysis, and the impact of base-level changes on the distribution of dispersion system was discussed. The results indicate that the Yaojia formation in the Xingxi area can be divided into two mid-term base-level cycles, with three identified lithological combinations. On seismic sections, the lithological combination of moderately-thick sandstones intercalated with thin mudstones corresponds to strong amplitudes; the lithological combination of composite thick interbeds corresponds to medium-strong amplitudes; and the lithological combination of thin interbeds corresponds to weak-medium amplitudes. In plane, the sand body dispersion system in the shallow-water delta primarily exhibited a lobe shape in the early stage of base-level rise, gradually transited into a retrogressive dendritic shallow-water delta in the middle-late stage of base-level rise, existed predominantly as progradational-weakly aggradational dendritic shallow-water deltas in the early stage of base-level fall, and appeared as lump-like deposits in the middle-late stage of base-level fall.
The Fengcheng formation of the Mahu sag in the Junggar basin is primarily composed of alkaline lake sediments. A large number of alkaline minerals are developed near the center of the alkaline lake. As a major type in these alkaline minerals, trona is an important industrial resource worthy of development. Currently, the trona intervals are mainly qualitatively evaluated by using the crossplot method, and a quantitative evaluation method is required. Based on core analysis and thin-section identification on alkaline minerals, together with previous research findings, the alkaline minerals in the Fengcheng formation are classified into four categories: trona, shortite; huntite, and searlesite, and their physical properties and impacts on both reservoir properties and oil-bearing property are identified. The influence of trona content on logging responses is analyzed, and a predictive model for trona content is developed by using the deep-to-shallow resistivity ratio. Core data uninvolved in the modeling are used for verifying the predictive model. It is found that the trona content predicted by the model and the trona content measured in the sample are in good agreement, with an average relative error of 5.67%, meeting the requirements for precise mineral content calculations. Finally, based on the logging evaluation results of trona content from eleven wells, the distribution of trona in the Fengcheng formation is clarified. The research results may provide a theoretical and technical support for trona resource evaluation.
Based on the analyses of cast thin section, scanning electron microscopy (SEM), X-ray diffraction (XRD) of whole rock and clay minerals, high-pressure mercury intrusion, and CT scanning, a detailed study was conducted on the dynamic diagenesis-pore evolution of the Chang 6 heterogeneous tight sandstone reservoirs in the southeastern Ordos basin. Then the characteristics of diagenesis and pore-throat evolution of different reservoir spaces were discussed.The accommodation of Chang 6 reservoir in the study area is classified into 3 types such as reservoir spaces dominated by residual primary intergranular pores, dominated by dissolution pores, and mixed pores. The mineral composition and textural maturity control the initial pore-throat structure of the reservoir, cementation and its intensity influence the tightness of the reservoir, and the pore throats formed due to dissolution affect reservoir storage performance. If the reservoir is mainly affected by compaction and chlorite cementation, then residual primary intergranular pores are dominant, and the fractures are isolated, mostly leading to reservoir spaces consisting of mesopores with sparse reticular throats, indicative of good storage but poor connectivity. If the reservoir is influenced by zeolite cementation-strong dissolution, then zeolite dissolution pores are dominant, resulting in excellent pore throat connectivity, often appearing as reservoir spaces consisting of mesopores with tree-like throats, indicative of the optimal accommodation. If the reservoir has undergone cementation of chlorite, and cementation-weak dissolution of zeolite, both zeolite dissolution pores and residual primary intergranular pores contribute to relatively good pore throat connectivity, often exhibiting reservoir spaces consisting of micropores to mesopores with dense reticular throats, with the storage and transportation capacity falling between the above mentioned two.
To determine the distribution of the carbonate gas reservoirs in Permian Taiyuan formation in Yishaan slope of the Ordos basin, based on the data of drilling, well testing, logging, and formation testing, the carbonate gas reservoirs in Taiyuan formation were analyzed using field outcrops, core samples, thin sections, electron microscopy scanning, high-pressure mercury intrusion, and fluid inclusion temperature measurements, and then sedimentary microfacies, petrographic characteristics, physical properties, pore structures, and fracture distribution were studied of the reservoir. The results indicate that the carbonate gas reservoirs in Taiyuan formation are low-porosity and low-permeability lithological gas reservoirs. Favorable plays control the reservoir distribution and gas enrichment. The gas reservoirs `are mainly distributed in the bioherm and bioclastic shoal microfacies zones. Bioherms are found in the eastern part of the study area, including Jiaxian, Zizhou, and Qingjian, while bioclastic shoals are developed in the western part of the study area, including Hengshan, Jingbian, and Pingqiao, exhibiting an obvious zoning of facies from west to east. The carbonate rocks in Taiyuan formation consist of micritic bioclastic limestone and algal-bounded limestone, in which biogenic pores, intercrystalline pores, dissolution pores, and microcracks serve as accommondation. Fractures play a crucial role in migration of oil and gas, and their development contributes significantly to the natural gas enrichment in the reservoirs.
In order to improve the accuracy of reservoir characterization for purpose of tapping the potential of remaining oil in the middle to late oil and gas field development stage, taking the shallow-water delta reservoir of the Huagang formation in C oilfield, Xihu sag, as an example, the reservoir architecture was investigated by using core, grain size, logging, and seismic data. The architecture patterns of composite channel sandbodies of shallow-water delta facies were established, and their spatial evolution was clarified. The results show that the H3c layer represents the upper plain-channel deposit of shallow-water-delta facies, which is dominated by vertically stacked thick sandbodies; the H3b layer represents the lower plain-channel deposit of shallow-water delta facies, in which laterally-migrated medium-thick sandbodies are developed; and the H3a layer represents the shallow-water delta-front deposit, which is featured with isolated thin sandbody. The development of vertical sandbodies was controlled by middle-term base-level cycle. As the lake level rose, the shallow-water delta in the study area formed a retrogradational sequence, and sandbodies evolved from sheet-like to isolated belt-like, resulting in deteriorating reservoir connectivity.
To determine the exploration potential of the shale gas in the Cambrian Niutitang formation in the Tongren area, northeast Guizhou, on the basis of X-ray diffraction experiments, the maturity of the shale of Niutitang formation-Bianmachong formation from Well QTD-1 was tested by using methods of bitumen reflectance, illite crystallinity and laser Raman spectroscopy. The results show that the shale of Niutitang formation-Bianmachong formation lacks vitrinite, making its maturity difficult to be evaluated using conventional vitrinite reflectance. The shale is not evaluated satisfactorily by using the reflectance of bitumen, due to its complex genesis and the impact of bitumen heterogeneity. The illite crystallinity method can only provide a rough range of maturity, with relatively large error due to the presence of clay minerals. In contrast, the laser Raman spectroscopy method is less affected by heterogeneity and has advantages such as simple sample preparation and non-destructive testing, which proves to be a more ideal testing approach. The equivalent vitrinite reflectance of the black shale of Niutitang formation in the study area ranges from 3.41% to 3.50%, indicating a late overmature stage.
In order to determine the temporal continuity and spatial orderliness of hydrocarbon charging and accumulation in fault areas, taking the Shangzhenzi farm-Zhuanjiao area at the southern margin of the Ordos basin as an example, the relationship between fracture formation period and reservoir distribution was analyzed, and the controls of fractures on Yanchang formation reservoir was discussed. The study shows that the fractures of three periods (Yanshanian movement episode II and III, and Himalayan movement) are developed in Yanchang formation, showing varying impacts on hydrocarbon migration and accumulation. Near-source oil reservoirs captured all the hydrocarbons generated from the source rocks in immature and mature stages, which were subsequently destroyed during the Yanshanian episode III and the Himalayan movement, leading to oil migration towards the areas far away from source rocks. In the southern part of the study area, close to the Weibei uplift, fractures are well connected longitudinally and sand bodies are well developed, allowing oil enrichment primarily in reservoirs far away from source rocks. In the northern part of the study area, oil is predominantly retained in reservoirs near source rocks. Consequently, fractures and sand bodies are connected to form a transport network that plays a role in adjusting reservoirs. By virtue of multi-stage fractures, resources in reservoirs near or far away from source rocks can be complemented and integrated.
Zeolites are widely distributed in sedimentary rocks, and they are diverse in genesis and complex in evolution characteristics. Controlled by sedimentary environment and diagenetic conditions, zeolites of different genesis are formed in different diagenetic sequences, and exhibit distinct combinations, occurrences, and frameworks. Zeolites can be divided into primary zeolites, hydrothermal zeolites, volcanic-altered zeolites, and mineral-transformed zeolites. Zolite framework can be characterized by the Si/Al ratio, based on which the zeolites are categorized into high-silica and low-silica zeolites. Zeolites play a strong catalytic role in hydrocarbon generation from source rocks. High-silica zeolites have lower catalytic activity, but slower deactivation rate than low-silica zeolites, and exhibit good selectivity. Zeolite cementation and dissolution have constructive and destructive effects on reservoirs, respectively. In different diagenetic sequences, zeolites show varying impacts on reservoir properties. The transformation of clay minerals to zeolites enhances the brittleness and water sensitivity of shale. Brittleness will increase the fracability of shale reservoirs, while water sensitivity will reduce reservoir permeability.
