Underwater Distributary Channel Research Articles

Evaluation of Sedimentary Characteristics of the Chang 9 Oil Layer Formation in the Yanchang Formation, Ordos Basin

Shallow-water deltas are a subject of sedimentary research and represent a significant target for oil and gas exploration. The Yanchang Formation of the Triassic in the Ordos Basin comprises numerous shallow-water delta blocks. This paper addresses the core issues pertaining to the sedimentary facies, sedimentary characteristics and sand body distribution of the Chang 9 oil layer formation of the Upper Triassic in the Ordos Basin. Guided by the relevant theories and methods of contemporary sedimentology and sedimentary geology, the reservoir characteristics are described and studied in detail through ordinary thin sections, cast thin sections, graphical representations of particle size and scanning electron microscopy experiments. The experimental results indicate that the porosity in the study area ranges from 3% to 12% and that the permeability is between 0 and 1.5 × 10−3 μm2, which is consistent with classification as an ultra-low-porosity and ultra-low-permeability reservoir. The Chang 9 sandstone is composed of feldspar sandstone and lithic feldspar sandstone. The average content of quartz is low, at less than 31%, while the average content of feldspar is high, at more than 34%. The average content of rock debris is between 10% and 20%. Therefore, the compositional maturity of the Chang 9 sand body is generally low. The particle size distribution exhibits a positive deviation, indicating that the sediments in the sand body are primarily coarse-grained components. The kurtosis of the particle size–frequency curve is observed to vary from flat to very sharp. The Chang 91 lake is classified as a shore shallow lake with basin subsidence and lake transgression. The Chang 9 period saw the development of the Chang 91 sedimentary facies into a semi-deep lake–deep lake environment. The vertical structural style of the Chang 9 oil layer formation in the basin can be roughly summarized into three basic structural types: the sedimentary structures observed in the area include box-shaped upward thinning, bell-shaped upward thinning and funnel-shaped upward thickening. The delta front area in Chang 9 is notable for its size and the prevalence of underwater distributary channel microfacies. The sand body distribution is stable, with sand layer thicknesses ranging from 15 to 30 m. The evaluation and summary of the sedimentary characteristics of the Chang 9 oil layer formation provide a geological basis for future exploration and development in the study area.

Sedimentary microfacies of Member 5 of Xujiahe Formation in the Dongfengchang area, Sichuan Basin

Member 5 of the Upper Triassic Xujiahe Formation (T3X5) in central Sichuan Basin has made a breakthrough in exploration recently. However, this new stratum has not been investigated sufficiently with respect to basic geology, making its types and distribution of sedimentary facies unclear, which severely restricts its subsequent exploration evaluation. In this study, types of sedimentary microfacies in the first sand group of T3X5 (T3X51) are clarified through core observation and logging interpretation using core, log and seismic data, and then distribution of sedimentary microfacies in T3X51 is determined according to seismic waveform features and seismic prediction. The results show that T3X51 in the Dongfengchang area is mainly composed of deltaic deposits of several microfacies, such as delta front underwater distributary channel, sheet sand, and interdistributary bay. On seismic sections, different microfacies are significantly different in waveform features, the underwater distributary channel is characterized by one trough between two peaks, while diversion bay exhibits chaotic reflections between T6 and T51. The sedimentary microfacies varied greatly during the depositional period of T3X51 in the Dongfengchang area, this is because that the sediment supply was mainly controlled by the southwest and southeast provenance regions. Three superimposed underwater distributary channels are developed in the Dongfengchang area. The phase-1 superimposed underwater distributary channel in the northwest transition to sheet sand in the northeast, the phase-2 superimposed underwater distributary channel in the south extends shortly, the phase-3 superimposed underwater distributary channel in the northeast has a large development scale. These research findings are helpful to guide the subsequent exploration of T3X5 gas reservoir and also theoretically significant for investigating the depositional evolution of the Xujiahe Formation in central Sichuan Basin.

Sedimentary Microfacies Types and Patterns of Chang 6 Member of Triassic Yanchang Formation in the Dalugou Area of Jing’an Oilfield in Ordos Basin, China

The sixth member of the Triassic Yanchang Formation (Chang 6 member) in the Dalugou area of the Jing’an Oilfield in the Ordos Basin is a typical ultra-low-permeability lithological reservoir. The Dalugou area has achieved some development progress in the past few years. With the development of the Chang 6 member in the Dalugou area, a better understanding of the sedimentary microfacies and depositional patterns is needed for precise oil development. The purpose of the study of the reservoir description is to understand the reservoir more accurately and provide a solid geological basis for the adjustment of the development strategy of the Chang 6 reservoir. The Chang 6 member of the Triassic Yanchang Formation in the Dalugou area of the Jing’an Oilfield belongs to the subfacies of the delta front, and the reservoir in the study area is mainly the underwater distributary channel deposition. There are two main depositional patterns in the study area: the dendritic sandstone depositional pattern and the lobate sandstone depositional pattern. The study on the sedimentary types and patterns of the Chang 6 member of the Triassic Yanchang Formation in the Dalugou Area of the Jing’an Oilfield can provide significant information for the evaluation of reservoir characterization. Furthermore, the heterogeneity of the Chang 6 reservoir under various depositional patterns has an important influence on oil enrichment.

Coupling Relationships between Sedimentary Microfacies, Sand Bodies, and Tectonic Fracture Characteristics in Braided River Deltas: A Case Study of the Bashijiqike Formation in the Keshen 2 Area

Fractures are crucial as main natural gas transport channels in tight sandstone reservoirs. In order to reveal the correlation between the combination of fractures in Block Keshen 2 and sandstone, we have collected drilling core data, logging curve data, imaging logging data, and rock thin-section data from the Bashjiqike Formation in the Keshen 2 area, and by classifying and statistically analyzing the different influencing factors of fractures, we have established a correlation between the development of fractures and sandstone thickness, lithology, and sedimentary microfacies. The results reveal the following: (1) frequent vertical superposition and lateral migration occur in the sedimentary sand bodies of the Bashijiqike Formation. Three types of patterns of sand bodies have been identified according to the changes in microfacies. Type I refers to the patterns of sand bodies developed in main subaqueous distributary channels, type II refers to the patterns of sand bodies developed in secondary subaqueous distributary channels or mouth bars, and type III refers to the patterns of sand bodies developed in isolated subaqueous distributary channels; (2) three types of fracture patterns have been described in the various sand bodies of the Bashijiqike Formation in the Keshen area, including high–medium-angle branch-like fracture patterns, medium-angle reticular fracture patterns, and isolated fractures; (3) the coupling relationship among sedimentary microfacies, sand body patterns, and fracture patterns has been established. The high–medium-angle branch-like fracture patterns mainly develop in the main underwater distributary channel and the type I sand body patterns. The medium-angle reticular fracture patterns mainly develop in the secondary underwater distributary channel and mouth bars, as well as the type II sand body patterns. Isolated fractures can occur in all sedimentary microfacies but are sporadically distributed within the three types of sand body patterns. The research results present the regularity of fracture development in fractured reservoirs, which can be applied to oil and gas fields with the same background, providing certain geological evidence for exploration and development.

Characteristics, logging identification and major controlling factors of bedding-parallel fractures in tight sandstones

More and more tight oil and gas exploration practices show that bedding-parallel fractures (BPFs) are closely related to hydrocarbon migration and accumulation. However, there is still a lack of studies on the detailed characterization, the logging identification method and the major controlling factors of BPFs. The tight sandstones in the northern Sanbian of Ordos Basin have developed numerous BPFs which are typical research objects. In this study, the development characteristics and oil-bearing of BPFs were firstly analyzed based on cores, thin sections and image logs. Then, constrained by the BPFs appearing in cores and image logs, the identification method of BPFs was established by conventional log curves. Finally, the major controlling factors for the formation of BPFs were discussed. Resultsshow that the oil-bearing of BPFs is markedly better than high-angle fractures (HAFs), which indicates that BPFs have a great significance to tight oil migration and accumulation in the northern Sanbian. The bedding-parallel fractures index (BPFI), which consists of the composite fracture index (CFI), fracture dip index (FDI) and principal component analysis (PCA), can identify the BPFs of tight sandstones, and the identification rate can reach 85% with the detection result of image logs. Fine sandstones with parallel bedding and cross bedding which easily enriched mica, underwater distributary channel sedimentary microfacies with comparatively strong hydrodynamic conditions, and a certain mudstone thickness that can produce differential compaction overpressure are the major factors affecting the development of BPFs.

Major advancement in oil and gas exploration of Jurassic channel sandstone in Well Bazhong 1HF in northern Sichuan Basin and its significance

In January 2023, Well Bazhong 1HF in the northern Sichuan Basin obtained high-yield industrial oil flow of over 100 cubic meters from the Jurassic channel sandstone for the first time, realizing a major breakthrough. In order to provide more support for further oil and gas exploration in this area, this paper analyzes the sedimentary and reservoir characteristics of the Jurassic Lianggaoshan Formation in Bazhong region of northern Sichuan Basin and their control factors based on the exploration achievements of Well Bazhong 1HF. Then, oil and gas reservoir characteristics and oil and gas sources are comparatively analyzed. Finally, the key technologies for the exploration of channel sandstone oil and gas with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity are researched and developed, and the next oil and gas exploration direction in the Lianggaoshan Formation of northern Sichuan Basin is pointed out. And the following research results are obtained. First, in the second member of Lianggaoshan Formation (“Liang 2 Member” for short) in Bazhong region, multi-stage underwater distributary sand bodies of delta front are developed with sandstone thickness of about 25 m and average porosity of 5.6%. The pore types are mainly primary intergranular pores and feldspar/debris intragranular dissolved pores, the pore throat structure is good, and the development of good-quality reservoirs is controlled by the sedimentary microfacies of underwater distributary channel. Second, the oil and gas reservoir of Liang 2 Member is a highly oil-bearing condensate gas reservoir/volatile oil reservoir, whose oil and gas is mainly sourced from the semi-deep lacustrine shale of Liang 1 and 2 Members. Third, channel sand bodies are superimposed and developed continuously in the upper part of Liang 2 and Liang 3 Members, and the source-reservoir configuration is good, with the characteristics of near-source hydrocarbon accumulation and overpressure hydrocarbon enrichment. Fourth, for the channel sandstones with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity, the reservoir prediction technology of “high-frequency sequence stratigraphy slice, seismic frequency decomposition and facies-constrained seismic waveform indication inversion” is developed to precisely characterize the “sweet spot” target of narrow channel sandstone, and the key fracturing technology of “dense cutting + composite temporary plugging + high-intensity proppant injection + imbibition and oil-increasing” is formed to realize the large-scale reconstruction of channel sandstone reservoir. In conclusion, the breakthrough of Well Bazhong 1HF in the exploration of Lianggaoshan Formation oil and gas in Bazhong region reveals the huge potential of Jurassic oil and gas exploration in the Sichuan Basin, and plays a positive role in promoting the exploration and development of the Jurassic channel sandstone oil and gas in the Sichuan Basin.

Application of Seismic Stratigraphic Slice Continuous Browsing Technology to Delicately Characterize River Sedimentary Microfacies

On the basis of understanding the regional tectonics characteristics and stratigraphic sedimentary characteristics of the study area, the sequence stratigraphic framework within the region is gradually studied by applying the principle of high-resolution sequence stratigraphy, and G4 oil formation is divided into three sets of sand formations, namely, G4 upper, G4 middle, and G4 lower sand formations, and divided into small layers in detail. Through comprehensive analysis of lithofacies, logging facies, and seismic facies, the sedimentary facies of the G4 oil formation are comprehensively analyzed. The main sedimentary facies type of the G4 oil formation is the delta front facies belt, and the most important sedimentary microfacies in the delta front facies belt are underwater distributary channel sedimentary microfacies. Using seismic sedimentology methods, make stratigraphic slices of each sub layer of the G4 oil formation, and use the rapid browsing method of stratigraphic slices to trace river sand in detail.

Hydrocarbon potential assessment of the lacustrine fan delta reservoirs in the Lower Cretaceous syn-rift Xing’anling Formation in the Beier Sag, Hailar Basin, Northeast China

Efficient exploration and development of oil and gas resources in complex geological environments continue to pose significant challenges for the energy industry. The localization and extraction of reservoirs in basins with complex structures, developed faults, and scattered sedimentary sand bodies are topics of international interest. One such basin, the Hailar Basin in northeastern China, represents a complex geological environment with heterogeneous distributions of oil and gas reserves, along with variable reservoir conditions, leading to challenges in hydrocarbon exploration and extraction. The Sudeert oil field, situated within this basin, is known for its high productivity; nevertheless, the underlying factors responsible for its success are not yet fully comprehended. Based on seismic, logging, and core data from the Sudeert oil field, as well as previous research, this study comprehensively analyzed the sedimentary environment, sedimentary facies characteristics, sand body distribution patterns, vertical stacking relationships of sand bodies, and hydrocarbon accumulation potential of the oil reservoirs in the Lower Cretaceous Xing’anling Formation in the Sudeert oil field. The Xing’anling Formation I and II oil reservoirs are deposited in a fan-delta front sedimentary environment, and the sedimentary microfacies that are conducive to the development of reservoir sand bodies include underwater distributary channels, underwater natural levees, estuary dams, front silt beds, and turbidite sands. Among them, the underwater distributary channel microfacies is the main depositional facies for the development of reservoir sand bodies. Three major depositional patterns of fan lobes can be identified within this depositional system: 1) isolated, 2) contact, and 3) superimposed lobes. Different combinations of lobes developed in different blocks and resulted in different sand body depositional patterns. The isolated lobes mainly developed in the western oil-producing (B28 block) due to the scarcity of sand and slowly increasing accommodation space. The contact lobes mainly developed in the central oil-producing block (B14 block) due to sufficient sediment supply and steadily increasing accommodation space across a wide area. The superimposed lobes mainly developed in the southeast oil-producing block (B16 block) due to sufficient sediment input and steadily increasing accommodation space within a restricted area. In the whole study area, the superimposed lobe pattern is the most favorable depositional pattern and forms the highest-quality reservoirs because of the high degree of sand body connectivity. These results also highlight the utility of sedimentary patterns and sand body assemblage studies for the oil exploration and development of similar rifted basins.

Interpretation of Sand Body Architecture in Complex Fault Block Area of Craton Basin: Case Study of TIII in Sangtamu Area, Tarim Basin

The complex fault block oilfields in the craton basin contain vast reserves of oil and gas resources. During the development of an oilfield, the flow of oil, gas, and water, is controlled by faults and configuration boundaries. The distribution of remaining oil and gas depends on the interpretation of the reservoir’s architecture. However, recognizing the faults and the architecture boundary remains a challenge, hindering the efficient development of these resources. This study proposes a new idea for interpreting the configuration of thick sand bodies. This study was conducted in order to interpret the fine architecture of thick sand bodies in the Sangtamu area, using core samples, well logging, and production data, guided by sedimentation patterns from ancient to modern times. Results indicate that the Sangtamu area is a braided river delta front sedimentary system, dominated by the backbone underwater distributary channel and branch-type underwater distributary channels. The backbone channel is larger in scale, with a relatively large rock grain size and a box-shaped logging curve, whereas the smaller-scale branch channels have a bell-shaped logging curve resulting from the gradual weakening of water energy. Sandstone bodies from different types of underwater distributary channels are spatially overlapped, forming thick plate-like sandstones. The architecture interface between channels can be used as the fluid seepage boundary and can help prevent bottom water intrusion to a certain extent. The remaining oil is primarily concentrated in the architecture boundary area, which presents the next potential tapping area.

Characterization of fractures in low‐permeability thin tight sandstones: A case study of Chang 6 Member, Yanchang Formation, western Ordos Basin

Structural fractures are formed when the underground rock mass deforms and exceeds its own strength limit, so they represent the complex geomechanical properties of rock. Small or core‐scale fractures usually extend less than 10 m in length, which affects the productivity of tight sandstone. Therefore, core‐scale fracture is the core factor for the prediction of reservoir sweet spots. In this paper, the research on the evolution and prediction of natural fractures in tight sandstone is investigated using the core, thin section, logging materials and numerical simulation methods. The results show that a large number of vertical and horizontal sliding fractures with shearing properties are developed in the tight sandstones of the Yanchang Formation. The particle size affects the compactible space inside the reservoir, which then affects the fracture development degree. Since the superimposed thin sand bodies are formed by the frequent lateral migration of the underwater distributary channels in the study area, therefore, the natural fractures in the thin sand bodies at the edge of river channels are relatively developed. According to statistics, the vertical extension distance of fractures is usually less than 2 m. Meanwhile, the fractured zones are mainly located in the cumulative sand body thickness range of 3 ~ 10 m. Moreover, the fractured zones are generally located in the high part of the structure and its wings. Regional structure and thin sand body distribution jointly affect the evolution of fractures in tight sandstones. Through this study, we found that fractures are more developed in thin sand bodies, and the controlling factors include lithology, sedimentary microfacies, sand thickness and local structure. The comprehensive evaluation of fractures in tight sandstones with high accuracy from 1D to 3D was achieved using core observation, logging interpretation, and three‐dimensional (3D) fracture modelling.

Sedimentary Microfacies and Sand Body Characteristics at Segment 2 of the Sangonghe Formation in Oilfield A on the South Slope District of the Mahu Depression

The South Slope District of the Mahu Depression in the Junggar Basin, a major favorable zone for middle and superficial oil–gas exploration, has experienced industrial gas flow. However, research on the sedimentary microfacies characteristics of Segment 2 of the Sangonghe Formation, the main oil-bearing formation, remains lacking. In this study, the rock type, sedimentary tectonics, and sedimentary microfacies of Segment 2 of the Jurassic Sangonghe Formation in the South Slope District of the Mahu Depression were thoroughly investigated through 3D seismic, rock core, and logging data. Moreover, the sedimentary modes and distribution characteristics of the sand bodies in the study area were further analyzed. Results showed that subfacies at the front edge of the braided river delta are developed at Segment 2 of the Sangonghe Formation, which can be further divided into four microfacies types, namely, underwater distributary channel, sheet sand, estuary dam, and interdistributary bay. The estuary dam is only developed at local positions in the work area. The vertical evolutionary laws from Segment 2 of the Sangonghe Formation to Segment 3 of the Sangonghe Formation are explicit and manifest as retrogradation from the subfacies at the front edge of the braided river delta to the prodelta. The sand bodies formed by frequent swings of the underwater distributary channels are the main reservoir bodies, and the lithology is mainly fine-grained feldspar lithic sandstone, and sedimentary tectonics have diverse forms. On the basis of deposition microphase analysis, the sand bodies’ planar distribution characteristics under phase-controlled conditions were analyzed using a seismic model inversion technology to provide theoretical guidance for oilfield expansion, exploration, and exploitation.

Microfacies types and distribution of epicontinental shale: A case study of the Wufeng–Longmaxi shale in southern Sichuan Basin, China

For black shales, laminae and bedding are hard to identify, grain size is difficult to measure, and trace fossils do not exist. Taking the Ordovician Wufeng – Silurian Longmaxi shale in southern Sichuan Basin, China, as an example, the types, characteristics and models of microfacies in epicontinental shale are analyzed by means of full-scale observation of large thin sections, argon-ion polishing field emission-scanning electron microscopy (FE-SEM), and kerogen microscopy. The epicontinental sea develops delta, tidal flat and shelf facies, with black shale found in microfacies such as the underwater distributary channel and interdistributary bay under delta front facies, the calcareous and clayey flats under intertidal flat facies, the calcareous and clayey shelfs under shallow shelf facies, the deep slope, deep plain and deep depression under deep shelf facies, and the overflow under gravity flow facies. Basinward, silty lamina decreases and clayey lamina increases, the grain size changes from coarse silt to fine mud, the silica content increases from about 20% to above 55%, the carbonate and clay minerals content decreases from above 40% to around 10%, and the kerogen type changes from type II2 to type II1 and type I. Provenance and topography dominate the types and distribution of shale microfacies. The underwater distributary channel, interdistributary bay, clayey flat, clayey shelf, and overflow microfacies are developed in areas with sufficient sediment supply. The calcareous flat and calcareous shelf are developed in areas with insufficient sediment supply. The deep shelf shale area is divided into deep slope, deep plain, and deep depression microfacies as a result of three breaks. The formation of epicontinental shale with different microfacies is closely related to the tectonic setting, paleoclimate, and sea level rise. The relatively active tectonic setting increases the supply of terrigenous clasts, forming muddy water fine-grained sediment. The warm and humid paleoclimate is conducive to the enrichment of organic matter. The rapid sea level rise is helpful to the widespread black shale.

Research on sand body architecture at the intersection of a bidirectional sedimentary system in the Jiyuan area of Ordos Basin

The exploration and development of the dual-provenance lower assemblage of the Yanchang Formation in the Jiyuan area has progressed rapidly. At the intersection of this bidirectional provenance system, a complex and variable spatial combination of sand bodies formed, resulting in significant structural heterogeneity in the development and distribution of reservoirs. Based on previous studies, this paper combines core data and logging data with a large number of analytical tests and production performance data to carry out research on the Chang 82–Chang 9 reservoir group in the lower assemblage of the Yanchang Formation in the Shijiawan-Buziwan area. Based on the analysis of sedimentary conditions, the sand body development pattern at the intersection of the bidirectional sedimentary system in the study area was analysed by stepwise dissection of the sand body architecture. After the types and characteristics of the 4th- to 5th-level architectural elements were determined, the spatial distribution of the combinations of these elements was assessed and combined with logging discriminant analysis and geometric shape prediction methods to identify a ‘prism’ architectural distribution pattern. The architectural elements are connected with the distribution of diagenetic facies, the spatial distribution patterns of different types of diagenetic facies under the constraints of the architecture are summarized by region, and the locations of potential favourable reservoir development are discussed. The results show that the degree of superposition and combination of the eight skeletal architectural elements in the target layers gradually deteriorate from the bottom to the top. In addition, the development scale and degree of architectural elements in the braided river delta system in the west are better than those in the meandering river delta system in the east. In the different sedimentary areas, the spatial combination styles of the architectural elements are quite different, and the combination of these elements gradually changes from a combination of braided channels (FA1) and abandoned channels (FA2) to a combination of underwater distributary channels (FA4). Matching of the distribution of diagenetic facies with the distribution of architectural elements reveals that the diagenetic facies dominated by intergranular pores and dissolution pores (associated with good reservoir physical properties) are usually found at the bottom or in the lower to middle parts of the skeletal architectural elements.

Effect of Authigenic Chlorite on the Pore Structure of Tight Clastic Reservoir in Songliao Basin.

Authigenic chlorite is a common clay mineral in clastic rock reservoirs, and it has an important influence on the pore structure of tight clastic rock reservoirs. In this paper, the tight clastic reservoirs in the Lower Cretaceous Yingcheng Formation in the Longfengshan subsag in the Changling fault depression in the Songliao Basin were investigated. Polarized light microscopy, scanning electron microscopy (SEM), X-ray diffraction (XRD), high-pressure mercury injection (HPMI), and low temperature nitrogen adsorption (LTNA) were used to study the influence of authigenic chlorite on the pore structure of tight clastic reservoirs. The results show that the authigenic chlorite in the study area was mainly generated in the form of pore linings. The formation of the authigenic chlorite was mainly controlled by the parent rock type and the sedimentary microfacies in the provenance area. The hydrolysis and dissolution of the iron- and magnesium-rich intermediate-mafic magmatic rocks and the high-energy, open, weakly alkaline reducing environment in the delta-front underwater distributary channel were the key factors controlling the formation of the authigenic chlorite in the study area. The pore-lining chlorite slowed down compaction and inhibited quartz overgrowth, protecting the original pores. Moreover, there are a large number of intercrystalline pores in the chlorite, which provided channels for the flow of acidic water and thus the formation of secondary pores, playing a positive role in the physical properties of the tight clastic rock reservoirs. However, the pore-filling chlorite also blocked the pore throats, playing a negative role in the physical properties of the tight clastic rock reservoirs. The tight clastic rock reservoirs with pore-lining chlorite generally had low displacement pressures and large pore throat radii. The morphology of the nano-scale pores was mainly parallel plate-shaped slit pores. There were many primary pores and a small number of secondary pores in the reservoir. Some of the pores were connected by narrow-necked or curved sheet-like throats, and the pore structure was relatively good. A higher relative content of chlorite led to a larger nano-scale pore throat radius, a smaller specific surface area, a smoother pore surface, and stronger homogeneity. Authigenic chlorite played a positive role in the formation of the tight clastic reservoirs in the study area.

Sedimentary Characteristics of Chang 81 Sub-Member of Yanchang Formation in M Area of the Ordos Basin

The Ordos Basin is a significant oil and gas basin. Region M is located southwest of the Ordos Basin. Its Chang 8₁ sub-member is primarily delta front, with abundant oil, and is the primary exploration and development target series. Deep research into the sedimentary facies of the Chang 8₁ sub-member has implications for oil and gas exploration. The study area is primarily delta facies, which is further subdivided into four microfacies: underwater distributary channel microfacies, underwater distributary channel inter-facies, estuarine bar microfacies, and sheet sand microfacies, based on core observation, logging interpretation results, and other data, combined with previous understanding and regional sedimentary background and other research results. During the Chang8₁ period, the entire area is dominated by multi-phase underwater distributary channel sand that is superimposed vertically and distributed in nearly east-west strips.

Research on infill adjustment method for XX narrow and thin sand body oilfield

The sedimentation of XX oilfield is mainly composed of underwater distributary channel sedimentation, and the sand body has the characteristics of “narrow, thin, and scattered”. Although basic well network development, primary and local secondary infill, edge expansion adjustment, and corresponding injection production relationship adjustments have been carried out, there are still problems in current development, such as poor well network adaptability, low utilization degree of thin and poor layers, fast production decline rate, long shut-in wells, and many inefficient wells. In order to explore the potential of infill adjustment in narrow and thin sand body oilfields and further improve oilfield recovery efficiency, well pattern infill adjustment work has been carried out, achieving good results. A supporting infill adjustment technology has been formed, which includes “well seismic joint fine reservoir prediction, multi-disciplinary research on remaining oil quantification, multi-parameter evaluation of infill well location optimization, and multi information fusion perforation layer optimization”, effectively improving the development effect.

Characteristics and genesis of deeply buried under-compacted sandstone and its comparison with normal Sandstone-A case in the lenghu tectonic belt, northern Qaidam Basin

Based on recovered core observations and thin section identifications combined with scanning electron microscopy images and statistics for physical properties, XRD analysis, and data for trace elements and carbon and oxygen isotopes, the genesis of under-compacted sandstone in the Lower Ganchaigou Formation of the Paleogene in the Lenghu VII structure in the northern Qaidam Basin has been confirmed through a detailed comparison with normal intervals for petrology, sedimentary environments and diagenetic characteristics. The results showed that under-compacted sandstone, developing in underwater distributary channels, was characterized by abnormal high porosity and large amount of intergranular pores. The genesis of intergranular pores is the intrusion of organic acid fluids, dissolution of calcite cements and restoration of primary pores. Conclusions could be drawn from the comprehensive comparison with normal interval. First, honeycomb-like chlorite grain coatings were much abundant (33%–58% in total clays) in the under-compacted sandstone comparing to it in normal interval and sandstone in adjacent area (<30%), indicating an intrusion of Mg-rich fluid leading to transformation from I/S to chlorite. Second, the carbonate cements content of the under-compacted sandstone (5.7%–17.3%) and the normal range (4.1%–20.3%) were both dominated by micrite calcite, and large amounts of early calcite residues resulting from dissolution were only found in the under-compacted sandstone. The δ18O value (17.36‰ ∼ −10.54‰) and the δ13C values (−5.12 to −3.51‰) indicated inorganic carbon dominated in carbonate cements; however, the small negative bias for δ13C in the under-compacted sandstone indicated that more organic carbon was contained than is typical. Third, the minor changes in the V/Zr, Ni/Zr, Co/Zr, Sr/Zr and Mo/Zr values suggested similar and stable paleoenvironments in both intervals. The weaker correlations among U/Zr, Ni/Zr and V/Zr indicated that U/Zr was affected by both the environment and fluid intrusion in the under-compacted sandstone. However, U/Zr was much larger (3.6–23.9) in the under-compacted sandstone than it is in normal sandstones (0.83–3.69), which indicated the invasion of acidic fluids originating from source rock.

Channel Evolution under the Control of Base-Level Cycle Change and the Influence on the Sustainable Development of the Remaining Oil—A Case in Jiang Ling Depression, Jiang Han Basin, China

The extension of river channels is one of the key factors in determining the remaining oil distribution. Different sedimentary facies and bedding types of oil layers will form specific characteristics of remaining oil distribution after water injection development. Using massive drilling, core, logging, seismic, and production data, on the basis of sequence stratigraphy base-level cycle change, the river records and development history are restored, and the fine connectivity of reservoirs and the configuration relationship of production wells are studied. The following conclusions are drawn: (1) A sequence stratigraphic division scheme is established. In the established sequence framework, the types and characteristics of reservoir sand bodies are analyzed. The 2nd and 6th members of Yu yang formation can be divided into 2 long-term base level cycles, 5 medium-term base level cycles, and 17 short-term base level cycles. The evolution of the second and sixth members of the Yu yang formation shows a pattern of base level rising, falling and rising again; (2) the vertical sedimentary evolution sequence is underwater distributary channel distributary channel meandering channel distributary channel flood plain. The types of channel sand bodies developed from little overlap to more vertical or lateral overlap and then gradually changed to isolated type; (3) according to the structural location and development sequence, different types of reservoirs are identified. Combined with the statistics of the drilled data of Yu yang formation k2y4 in Fu I fault block, it is found that the connectivity rate of oil layer thickness (the ratio of oil layer connectivity thickness to total thickness of sand layer) within the oil-bearing area is 84.4%, and the connectivity rate of the number of layers (8) is 60%. The connectivity condition is relatively good.

Densification mechanism of deep low-permeability sandstone reservoir in deltaic depositional setting and its implications for resource development: A case study of the Paleogene reservoirs in Gaoshangpu area of Nanpu sag, China

A better understanding of reservoir densification mechanisms is very important for petroleum exploration and controlling the reservoir quality distribution in low-permeability reservoirs. Low porosity and low permeability, difficult reconstruction, and economic infeasibility are important factors restricting its efficient production. Systematic analysis was performed to study the evolution of different microfacies in the deltaic depositional setting of the Paleogene deep low-permeability Gaoshangpu reservoir, define their genetic mechanisms, delineate the dominant facies belts, and define the favorable diagenetic sequences that are important for exploration of high-quality reservoirs. To understand the tight genesis of the low-permeability reservoirs, we analyzed the sedimentological and diagenetic evolution characteristics of various microfacies (i.e., underwater distributary channel, distributary bay, mouth bar, and front sheet sand) using core data and physical property analysis of the reservoir sand body. The results show the underwater distributary channel and estuary bar sand body with medium-to fine-grained and poor–medium sorting. The diagenesis is dominated by strong compaction, calcareous, argillaceous cementation, and dissolution during stage B in early diagenesis and stage A in middle diagenesis. In the fan delta environment, the weak anti-compaction resistance of low-permeability reservoirs is mainly due to the large content of plastic particles, finer grain size, and medium–poor sorting, with an average porosity reduction rate of 65%. This is a key factor for densification of reservoirs above 3000 m. Comparison among different sandstone microfacies of the deltaic setting shows that the sand body of the underwater distributary channel with low shale content has slightly stronger compaction resistance. The porosity reduction is not obvious at the depth of 3,000–4,000 m, but the loss of permeability at this depth section is significant, and the reservoir improvement from later dissolution is most obvious at this depth section. Calcareous cementation is the cause for densification of some mouth bars in the early stage and of underwater distributary channels in the middle and late stage. Under the influence of strong compaction and calcareous-filling pore throat, the sand body of the mouth bar has been basically densified at 3,000 m, resulting in limited reservoir transformation from later dissolution. The study shows that compaction is the main cause of reservoir densification, argillaceous and calcareous cementation is the secondary cause, and later dissolution is another main cause of reservoir enhancement. The research results can provide a reference and direction for reservoir development and search for the high-quality sweet spot in the deep and low-permeability reservoir.

Controlling effect of source-reservoir assemblage on natural gas accumulation: A case study of the upper triassic xujiahe formation in the sichuan basin

The enrichment law of tight sandstone gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin has not been fully revealed. In this study, the controlling effect of source-reservoir assemblage on gas accumulation in the Xujiahe Formation was systematically investigated. The results show that pores and fractures are developed in the tight sandstone reservoirs of the Xujiahe Formation. The main pore types are intragranular dissolved and intergranular pores. The quality of sandstone reservoirs in the Xujiahe Formation is controlled by sedimentation, diagenesis and tectonic processes. Underwater distributary river channels and estuary bars are favorable microfacies for reservoir development, and chlorite cemented facies and dissolution-kaolinite cemented facies are the most favorable diagenetic facies. In addition, the natural gas composition and carbon isotope characteristics of the Xujiahe Formation are significantly different in different intervals of the same gas field and the same interval of adjacent gas fields. This shows that the natural gas has no obvious vertical mixing and lateral migration, and it has the distribution characteristics of “local enrichment”. Then, the natural gas will be preferentially charged in the feldspar lithic sandstone and feldspar quartz sandstone with large thickness and good physical properties by means of short-range migration. According to the research, the hydrocarbon supply capacity of the single layer in each interval is weak, and it leads to the low filling degree of the gas reservoir and the insufficient separation of gas and water. On the whole, four sets of extra-source “lower generation and upper storage” assemblages and two sets of “self-generation and self-storage” source-reservoir assemblages are developed in the Xujiahe Formation. The development scale of natural gas is mainly controlled by the type of source-reservoir combination, and the areas with close source-reservoir contact and high hydrocarbon generation intensity are high-quality reservoir development areas.