Petroliferous Basins Research Articles

Dynamics mechanism and quantitative evaluation of effective reservoirs in petroliferous basins

Effective reservoirs in petroliferous basins are generally defined as rocks that have relatively high porosity and permeability, which have the capacity for accumulating and storing hydrocarbons under the conditions of sufficient hydrocarbon supply. Previous studies show that the lower limit of porosity of effective reservoirs decreases with increasing burial depth. However, the existing assessment methods for effective reservoirs mainly use well test data or petrophysical properties of a reservoir, without considering the influence of depth. These methods are not practical for petroleum exploration. In this study, the dynamic mechanism of hydrocarbon accumulation was studied using physical simulation experiments, which revealed that capillary force is a basic control for hydrocarbon accumulation. The relationship between the capillary force ratio of surrounding rock to reservoir rock and their oiliness was statistically analyzed. Finally, a novel discriminating standard and quantitative evaluation for determining effective reservoirs was established and its reliability was confirmed. This study shows that the capillary force ratio of surrounding rock to reservoir rock determines the reservoir effectiveness. Moreover, a reservoir is more effective when the ratio is larger, thus more favorable for hydrocarbon accumulation. The reservoir potential index (RPI) ranging from 0 to 1 is introduced to characterize the hydrocarbon-bearing property of a reservoir. Rservoirs are classified as effective reservoirs when RPI <1 and ineffective reservoirs when RPI >1. The effective reservoirs are further divided into four grades based on the RPI value: Grade I: 0 ≤ RPI ≤0.25; Grade II: 0.25 < RPI ≤0.5; Grade III: 0.5 < RPI ≤0.75; Grade IV: 0.75 < RPI <1, in which the grade I refers to the most favorable reservoir. It is conformed as a practical and reliable method.

Development of Songliao Basin by Palaeo‐Pacific slab rollback: Evidence from Early Cretaceous rhyolites in SK2 Borehole, NE China

As the largest petroliferous basin in northeast (NE) China, Songliao Basin preserves continuous Cretaceous sedimentary‐volcanic records, providing an excellent opportunity to recover the palaeo‐environment. The Yingcheng Formation in the Songliao Basin contains ample gas reservoirs that attract widespread attention. Whereas the timing, petrogenesis and geodynamic mechanism of the volcanic rocks in the Yingcheng Formation are still controversial, which largely constrain our understanding of the formation and evolution of the Songliao Basin. Here, we present an integrated investigation of zircon U–Pb ages and Hf isotope, as well as whole‐rock elements and Sr‐Nd isotopes data for a suite of rhyolites of Yingcheng Formation from the SK2 Borehole of NE China. Zircon U–Pb age dating results of nine samples have yielded a concentrated age of ~110 Ma. These Yingcheng rhyolites are characterized by high SiO2 (66–78 wt%) and alkali (Na2O + K2O = 7.80–11.70 wt%) content, high 10000*Ga/Al (1.26–3.82, mostly &gt;2.6) and FeOT/(FeOT + MgO) ratios (0.81–0.95), which show geochemical affinities with A‐type rhyolites. They have relatively low Y/Nb (0.69–1.78, average 1.19) and Rb/Nb (1.58–6.52, average 4.34) ratios, suggesting that the Yingcheng volcanic samples belong to A1‐type rhyolites which formed in an intraplate environment. These Yingcheng rhyolites show depleted Nd‐Hf isotopic compositions (εNd(t) = 2.43–4.87 and zircon εHf(t) = 4.22–9.88) comparable with the Early Cretaceous A‐type and I‐type rhyolites in the Songliao Basin, suggesting that they were originated from a juvenile continental crust. They were most likely derived from the partial melting of anhydrous lower crust instead of differentiation of mantle‐derived or mixing with alkaline basaltic magma, due to their low Mg# and absence of the coeval mafic rocks. Combined with the previous studies, A‐type rhyolites in the Yingcheng Formation erupted lasting at least 10 Myr and were widely distributed in the rifts of the Songliao Basin. We propose that the Yingcheng rhyolites were most likely generated from the rollback of the Palaeo‐Pacific Plate in the Early Cretaceous, thus highlighting the significance of the subduction of the Palaeo‐Pacific Plate during the secular evolution of the Songliao Basin.

Using monazite U-Pb geochronology of Precambrian shales to constrain fluid flow and hydrocarbon accumulation events of a petroliferous basin

Obtaining precise ages of the Phanerozoic fluid flow events of petroliferous basins is essential for understanding the tectonothermal histories, petroleum- and ore-forming processes. Conventional isotopic dating methods are often compromised by inheritance from detrital constituents and/or subsequent thermal resetting. Monazite is a trace mineral widely present in low-grade metasedimentary rocks, and as an excellent U–Th–Pb geochronometer it has great potential in dating fluid flow activities related to basin evolution. We present results of an in-situ monazite U-Th-Pb geochronology study on shale samples from the Neoproterozoic (651 Ma) Datangpo Formation intersected by a drill-hole in the Sichuan Basin, a typical petroliferous basin in western South China. We recognized two fluid flow events at ca. 450 Ma and ca. 263 Ma, and relate the former to the far-field effect of the Proto-Pacific Ocean subduction and the latter to emplacement of the Emeishan large igneous province. We infer that the ca. 450 Ma fluid flow event induced the first stage of oil charging in the paleo oil pools in the Sichuan Basin, as also recorded by the bitumen samples from the Anyue gas field which yielded re-Os isotopic ages of 458–492 Ma, whereas the ca. 263 Ma event triggered the gas generation of the Paleozoic marine strata in the Sichuan Basin. The results and findings of this study have important implications to reconstructing the complex histories of fluid flow, oil charging and gas generation events of petroliferous basins.

Hydrocarbon expulsion model and resource potential evaluation of high-maturity marine source rocks in deep basins: Example from the Ediacaran microbial dolomite in the Sichuan Basin, China

Hydrocarbon expulsion features and resource potential evaluation of source rocks are crucial for the petroleum exploration. High-maturity marine source rocks have not exhibited a hydrocarbon expulsion mode owing to the lack of low-maturity source rocks in deep petroliferous basins. We considered the Ediacaran microbial dolomite in the Sichuan Basin, the largest high-maturity marine gas layer in China, to exhibit a method that quantitatively characterizes the hydrocarbon expulsion of high-maturity marine source rocks. The experiment of fluid inclusion, rock pyrolysis, and vitrinite reflectance (Ro) of 119 microbial dolomite core samples obtained from the Dengying Formation were performed. A hydrocarbon expulsion model of high-maturity source rock was established, and its resource potential was evaluated. The results showed that the Ediacaran microbial dolomite in the Sichuan Basin is a good source rock showing vast resource potential. The hydrocarbon expulsion threshold is determined to be vitrinite reflectance at 0.92%. The hydrocarbon expulsion intensities in the geologic history is high with maximum of 1.6 × 107 t/km2. The Ediacaran microbial dolomite expelled approximately 1.008 × 1012 t of hydrocarbons, and the recoverable resource was 1.5 × 1012 m3. The region can be categorized into areas I, II, III, and IV, in decreasing order of hydrocarbon expulsion intensity. Areas with a higher hydrocarbon expulsion intensity have a lower drilling risk and should be prioritized for exploration in the order I > II > III > IV. Two areas, northern and central parts of Ediacaran in the Sichuan Basin, were selected as prospects which had the drilling priority in the future gas exploration. The production data of 55 drilled wells verified the high reliability of this method. This model in this study does not require low-maturity samples and can be used for evaluating high-maturity marine source rocks, which has broad applicability in deep basins worldwide.

Accumulation mechanism of mantle-derived helium resources in petroliferous basins, eastern China

Accumulation mechanism of mantle-derived helium resources in petroliferous basins, eastern China

Architectural Element Analysis of Nonmarine Oil and Gas Reservoir in China, the Research History, Progress and Future Trend: A Review

Since Miall’s architectural element analysis (AEA) was introduced to China in 1986, the method has been widely applied to studying the heterogeneity of oil and gas reservoirs in China. The development history, research field, research progress, and potential limitations of AEA in China have been reviewed based on 601 Chinese documents retrieved from the China National Knowledge Infrastructure (CNKI) database and some English documents retrieved from various databases. The development of sedimentary AEA in China experienced four stages: (1) the conceptual and introduction stage (1985–1995), (2) the test and trial stage (1995–2005), (3) the popularization and application stage (2005–2015), and (4) the innovative stage (2015 to present). The research field covers all reservoir types of continental petroliferous basins in China. Papers published on AEA were distributed in the fields of (1) alluvial fan reservoirs, (2) braided channel reservoirs, (3) meandering channel reservoirs, (4) fan delta reservoirs, (5) braided river delta reservoirs, (6) shallow-water delta reservoirs, (7) large-scale delta reservoirs, (8) beach and bar reservoirs, and (9) lacustrine deepwater gravity flow reservoirs. Among all these fields, the architecture of alluvial fans, braided channels, meandering channels, braided river delta, and fan delta reservoirs was mainly researched. AEAs in China have made outstanding innovations in hierarchical sedimentary boundary surface classification, depositional architectural models, and quantitative reservoir architectural modeling. Combining the hierarchical AEA with geostatistical modeling, big data, and artificial intelligence technology and comprehensively using geology, geophysics, and production information to realize the hierarchical integrated reservoir architectural characterization are the development directions of the AEA in China and around the world.

A comparative study of oil shale deposition in the Upper Cretaceous Nenjiang Formation, NE China: Evidence from petrographic and geochemical analyses

The Songliao Basin located in NE China is one of the most petroliferous basins in the world. The Upper Cretaceous Nenjiang Formation is an important source rock in the basin owing to its rich development of oil shale successions. From outcrop observation, we found that the oil shale successions can be divided into two types. The type I oil shale (TY1) is composed of multiple thin oil shale layers (∼1 m) interbedded with organic-poor shale layers and is typically developed in the first member of Nenjiang Formation (K2n1), whereas the type II oil shale (TY2) developed one thick succession of oil shale (∼10–15 m) and was mainly found in the second member of the Nenjiang Formation (K2n2). To compare the difference in forming mechanisms with two types of oil shale successions, petrographic characteristics, stable isotopic compositions, and geochemical elements were analyzed from two outcrops (i.e., Yaojia Station and Houjingou Outcrops). Based on the results, a notable higher δ13Corg values are recorded in the TY1, suggesting accelerated primary productivity. The observation of tuff layers and the relatively high P and Fe contents reveal that the frequent volcanic activities would have brought nutrient supply to the Songliao paleolake, thereby stimulating primary productivity and contributing to the deposition of multiple thin-layered oil shales. In contrast, the TY2 show decreased bulk sediment δ15N suggests intensified denitrification under anoxic conditions. Combined with elevated trace elemental ratios and increasing trend of CIA, we attributed these changes to marine transgression that occurred at the beginning of K2n2 deposition. Such conditions increased the accommodation space and favored the formation of stratified, anoxic bottom waters, which might have promoted organic matter preservation and further responsible for the deposition of thick oil shale succession in K2n2.

Fault Evolution and Its Effect on the Sealing Ability of Mudstone Cap Rocks

To study the spatial distribution and scale of oil and gas near faults in petroliferous basins, a prediction model is established for the degree of damage that faults in different stages of evolution exert on the sealing ability of mudstone cap rocks by calculating the stages and degree of fault damage to the sealing ability of mudstone cap rocks. This model is applied to the Nanpu 5th Structure and the results show that at survey lines L2 and L8, the F1 Fault destroyed the sealing capacity of mudstone cap rock of the 2nd member of Dongying Formation (E3d2). The undamaged cap rock stage, when the degree of damage was zero, persisted from 23.8 to 16.0 Ma at survey line L2 and from 23.8 to 13.6 Ma at survey line L8. Complete destruction, i.e., where the degree of damage was 100%, at survey lines L2 and L8 occurred from 16.0 to 13.3 Ma and from 13.6 to 13.3 Ma, respectively. The partial destruction stage began 13.3 Ma ago and persists today; the degrees of damage at survey lines L2 and L8 were 89.96% and 82.58%, respectively. This was not conducive to oil and gas accumulation in the reservoir under the mudstone cap rock of E3d2. These results agreed with the current findings of small amounts of oil and gas under the mudstone cap rock of E3d2 at survey line L8 and no oil and gas at survey line L2. This indicates that the model is feasible for predicting the degree of damage to the sealing ability of the mudstone cap rocks by faults at different stages in their evolution.

Architectural characteristics, evolutionary stages, and sedimentary models of clastic beach bars

Beach bars are important reservoirs and have good exploration potential in several petroliferous basins globally. At present, we urgently need to make a further study on beach bars based on previous studies to promote the process of oil and gas exploration and development, regardless of modern or ancient sedimentation. Using satellite maps, research achievements of predecessors and theoretical analysis as our references, we selected four typical areas of beach bars. Based on field surveys and core observations, we tried to divide beach-bars into three types, corresponding to five architectural units. We applied manual and machine learning recognition to categorize the architectural units observed in the study areas. Based on the sedimentary and environmental characteristics of architectural units, we summarized the sedimentary evolution stages and established the sedimentary models of each beach bar. The results indicated that the beach bars could be divided into shore beaches, submerged beaches and bars, based on different sedimentary and environmental characteristics. The shore beach includes the backshore and part of the foreshore (swash zone). The submerged beach has a swamp, part of the foreshore (except the swash zone) and the shoreface. Bars may appear anywhere on the shore-shallow sea/lake. The architectural units of beach bars were divided into five subtypes, corresponding to four evolutionary stages based on hydrodynamic traits and the sedimentary environment. Additionally, a discrimination standard was established based on principal component analysis and Bayesian discrimination on the Shahejie Formation of the Dongying Depression while using fine-scale recognition to verify the units. The coincidence between manual recognition and machine recognition results was 94.8%. We hope that our methodology and models will help address the limitations in previous studies on beach bar reservoirs and will help promote improvements in the related theories and optimization of their exploration and development.

Pore types, genesis, and evolution model of lacustrine oil-prone shale: a case study of the Cretaceous Qingshankou Formation, Songliao Basin, NE China

A comprehensive characterisation of the pore structure in shale oil reservoirs is essential for forecasting oil production and exploration risks. This study forecasted these risks in the oil-rich Songliao Basin using combination of high-resolution field emission scanning electron microscopy and quantitative X-ray diffraction to analyze the pore genesis and evolution mode within the first member of the Cretaceous Qingshankou Formation (K2qn1). The results showed the dominance of inorganic pores over organic pores, wherein diagenetic processes, such as compaction, pressure solution, and cementation, were responsible for the destruction of pore structure in the formation. Notably, the pores formed by dissolution and shrinkage cracks resulting from clay mineral transformation improved the oil storage space. Furthermore, according to the geochemical data and clay composition, the K2qn1 shale is in the middle diagenetic stage A, which can be further subdivided into A1 and A2 stages from top to bottom. The porosity slowly decreased in both sub-stages A1 and A2, wherein the decrease was stable in the latter. The diagenetic observations in this study are significant for the exploration of unconventional shale oil in petroliferous basins worldwide.

Volcanic reservoirs lacking a paleoweathering crust in Carboniferous deposits of the Junggar Basin, western China: Characteristics, controlling factors and hydrocarbon potential

The Junggar Basin is the basin with the richest exploration results of volcanic reservoirs among petroliferous basins in China. The oil test data and production data show there also exhibit good hydrocarbon displays in the Kebai Fault Zone where the paleo-weathering crust is not developed. In this study, we utilized core data and thin sections to investigate volcanic reservoir rocks lacking paleo-crusts of weathering in Carboniferous deposits in the western Junggar Basin, Northwestern China. The studied interval is dominated by seven types of volcanic rocks, two types of metamorphic rocks and three types of sedimentary rocks, which are grouped into six lithofacies. From northeast (NE) to southwest (SW) of study area, the dominant rock type changes from sedimentary rock, to pyroclastic rocks, tuffites, and then to welded pyroclastic rock, lavas, respectively volcanic rocks. And the corresponding dominant lithofacies changes from delta facies, to volcanic-sedimentary facies, explosive facies, and then to sub-volcanic facies, and effusive facies. Fault-induced fractures and dissolved pores are the dominant reservoir space types. Faults and lithology jointly played a significant role in controlling the macro-distribution, physical properties, and hydrocarbon accumulation in volcanic reservoirs. The geological setting controlled the influences of primary and secondary processes. This study also reveals that the volcanic lavas with high-angle fractures of effusive facies located in SW of the study area are favorable lithofacies for hydrocarbon accumulation. This study highlights the differences in volcanic reservoir rocks with and without paleo-crusts of weathering in terms of reservoir spaces, controlling factors and hydrocarbon accumulation. This study also reveals that volcanic reservoir lacking paleo-crust of weathering can have a high hydrocarbon potential.

Analysis of the world oil and gas exploration situation in 2021

The global exploration investment, new oil and gas discoveries, exploration business adjustment strategies of oil companies in 2021, and future favorable exploration domains are systematically analyzed using commercial databases such as IHS and public information of oil companies. It has been found that the world oil and gas exploration situation in 2021 has continued the downturn since the outbreak of COVID-19. The investment and drilling workload decreased slightly, but the success rate of exploration wells, especially deepwater exploration wells, increased significantly, and the newly discovered reserves increased slightly compared with last year. Deep waters of the passive continental margin basins are still the leading sites for discovering conventional large and medium-sized oil and gas fields. The conventional oil and gas exploration in deep formations of onshore petroliferous basins has been keeping a good state, with tight/shale oil and gas discoveries made in Saudi Arabia, Russia, and other countries. While strengthening the exploration and development of local resources, national, international, and independent oil companies have been focusing on major overseas frontiers using their advantages, including risk exploration in deep waters and natural gas. Future favorable exploration directions in the three major frontiers, the global deep waters, deep onshore formations, and unconventional resources, have been clarified. Four suggestions are put forward for the global exploration business of Chinese oil companies: first, a farm in global deepwater frontier basins in advance through bidding at a low cost and adopt the “dual exploration model” after making large-scale discoveries; second, enter new blocks of emerging hot basins in the world through farm-in and other ways, to find large oil and gas fields quickly; third, cooperate with national oil companies of the resource host countries in the form of joint research and actively participate exploration of deep onshore formations of petroliferous basins; fourth, track tight/shale oil and gas cooperation opportunities in a few countries such as Saudi Arabia and Russia, and take advantage of mature domestic theories and technologies to farm in at an appropriate time.

Development status and prospect of tight sandstone gas in China

As one of the important types of unconventional gas, tight gas is widely distributed in various major petroliferous basins in the world. The breakthrough of reservoir reconstruction technology and the reduction of development cost promote the scale and industrial development of tight gas. China is the third largest tight gas producer in the world and its yearly tight gas production is up to 470 × 108 m3 in 2020. In order to evaluate the development prospect of tight gas in China, this paper systematically summarizes domestic key technical series developed in the last 20 years' tight gas practice, after briefly analyzing the distribution and development history of tight gas resources all over the world. Then, the prospect of tight gas development in China is based on CNPC's fourth resource evaluation results. And the following research results are obtained. First, tight gas resource in China is abundant, accounting for about 10% of global resources, and its development is divided into two stages, i.e. the development evaluation stage and the development adjustment stage. Second, key technologies in the development evaluation stage include the establishment of genesis unit of effective reservoir, enrichment area selection, development index evaluation, well pattern and type optimization, reservoir reconstruction, and development scheme optimization. Third, the core in the development adjustment stage is enhanced gas recovery (EGR). The main technical means are well pattern optimization and infilling. Which can increase the recovery factor by 10%–20%. In addition, layer reviewing and reperforating, old well sidetracking, secondary fracturing, drainage and gas recovery, and pressurized production are also effective technologies. In conclusion, tight gas still has greater production potentials and development prospects in China. The potential tapping of produced proved reserves, the development of unproduced proved reserves and the effective development of new proved reserves are three important aspects to ensure the mid- and long-term development of tight gas. The first two aspects can support the yearly tight gas production to reach the peak of (700–800) × 108 m3 in 2030–2035 and keep stable production for more than 10 years. Moreover, the continuous development of new proved reserves will further support the stable production of tight gas until 2050–2060.

Quantitative Evaluation of Gypsum-Salt Caprock Sealing Capacity Based on Analytic Hierarchy Process—A Case Study from the Cambrian in the Tarim Basin, Western China

Gypsum-salt caprock is one of the most important caprocks in petroliferous basins around the world. Its sealing capacity extremely affects hydrocarbon accumulation and distribution. However, there are numerous variables that affect caprock sealing performance, making a quantitative evaluation challenging. The analytic hierarchy process (AHP), which has the advantage of turning several influencing factors into multi-level single objectives, can be utilized in this context to quantify the weight of each element impacting caprock sealing capacity. As a result, using the Tarim Basin’s Cambrian as an example, this article quantitatively assessed the gypsum-salt caprock sealing capacity using AHP. The results show that factors affecting the sealing capacity of Cambrian gypsum-salt caprock in the Tarim Basin can be summarized into three major categories and nine sub-categories, including the lithology (rock assemblage type and lithology zoning), the thickness (total thickness of thick single layer, maximum thickness of thick single layer, total thickness, and ratio of caprock to stratum), and the mechanical properties (internal friction coefficient, compressive strength, peak strength). The sealing ability evaluation index (C) was created by applying AHP to quantify a number of different characteristics. The capacity of the caprock to seal is inversely correlated with the C-value. The value of C in the plane climbs consistently from Tabei to Tazhong and subsequently to the Bachu region, indicating a steady improvement in caprock sealing ability. Additionally, the evaluation’s findings are in line with how hydrocarbon accumulations are currently distributed. Furthermore, hydrocarbons are mostly distributed in subsalt and subsalt-dominated layers when C is greater than 2. On the contrary, hydrocarbons are mainly distributed in post-salt layers when C is less than 2. Furthermore, in areas affected by faults, hydrocarbons are favorably distributed in subsalt layers when C reaches 2, and fault activity is poor or strong in the early period and weak in the late period.

Assessment of the thermal maturation, organofacies, and petroleum generation history of Sirte Shale Formation in Sirt Basin, Libya

The current study is conducted to investigate the upper Cretaceous (Campanian) Sirte shale Formation to better understand the regional abundance of the organofacies, thermal maturation levels, and the petroleum generation and expulsion histories during the geological time in one of the most important petroliferous basins in North Africa (Sirt Basin). Rock-Eval pyrolysis analysis of 988 samples in 56 wells that penetrated the Cretaceous section in the Sirt Basin was used to screen and study the geological and geochemical characteristics of the Sirte shale Formation. Multi-dimensional basin modeling, including 1D burial histories and 2D modeling approaches, was calibrated with %VRo and pyrolysis Tmax data to establish refined regional maturity of the Sirte shale Formation. By using the Rock-Eval data, the type, occurrence, and distribution of organofacies in time and space were investigated using analytical assessment procedures and present-day mapping, such as total organic carbon (%TOCp), hydrogen index (HIp), and kerogen transformation ratio (TRp) to define the lateral and vertical special variation. Key biological marker (biomarkers) data is used to determine their special types, abundance, and host sedimentary environments. We used integrated geochemistry with basin modeling to define the Sirte shale petroleum generation and expulsion history, petroleum phase-type and quantity, and expulsion efficiency. Results indicate that the current maturation levels in the general range of 0.4–1.35 %VRo (equivalent to 405 °C–460 °C pyrolysis Tmax) that found to allow Sirte shale Formation to enter transformation levels ranging from 20% to 91%, which is equivalent to 1,615 m–3,627 m burial depth. Sirte shale Formation is dominated by two types of organofacies (B and D/E), which are characterized by %TOC up to 5% and hydrogen index from 400 to 700 mg HC/g TOC with sudden lateral and vertical variation due to the influence of the marine and transitional – terrestrial sedimentary environments. Similar indications from the biomarker data were Pr/Py ratio shows a significant existence of anoxic and dysoxic environments (generally, 0.4–2.4). Alga marine (dominant), mixed, and minor terrestrial organic matter was defined to dominate the Sirte shale Formation as indicated by Pr/nc-17 and Py-nc18 data. The petroleum generation history of the Sirte shale Formation occurred in the Oligocene time (∼30 Ma). The higher expulsion efficiency for the oil phase, up to 84% detected in the deeper parts of the basin, and lower gas expulsion efficiency with its maximum up to 63%. During the geological time, two primary petroleum phases were generated and expelled (oil and gas) from the Sirte shale. The bulk fluid properties generated from Sirte Shale Formation indicate that range of GOR from 400 to 2000 scf/bbl and API in the range of 30–60.

Opening of the South China Sea marginal basin: Insights from the tectonic evolution of the ENE-striking Littoral Fault Zone

The northern South China Sea (SCS) continental margin has a very complex geological history within a multiplate convergent setting and has experienced multiphase tectonic movements, during which the largest significant petroliferous basin, the Pearl River Mouth Basin (PRMB), developed. Along the northern boundary of the PRMB, a prominent wide ENE-striking intraplate deformation zone, the Littoral Fault Zone (LFZ), stretches from west to east and is considered to be the major fault structure that formed during the spreading of the SCS and rifting of the northern continental margin. However, a lack of direct constraints on stratigraphic records and fault intersections due to difficulties with offshore geophysical exploration has resulted in uncertainty about the nature of the LFZ, especially the location, geometry and deep–shallow structural coupling, which are still unclear. In this paper, we use newly collected enhanced images provided by 2D long-offset multichannel seismic reflection profiles across the LFZ Pearl River Mouth (PRM) segment to analyse the deep structural and stratigraphic elements along the LFZ. Combining these data with previous findings, we attempt to advance the understanding of the NE–ENE-striking LFZ nature, evolutionary history and controlling effect on the tectonic and sedimentary processes that led to the formation of the PRMB. The results of this work shed new light on the geodynamic processes surrounding the PRMB. We suggest that the LFZ acted as a northern boundary fault with a three-phase transition over time. The first phase of fault activity initiated as a low-angle basement decollement (phase 1), followed by high-angle SE-dipping normal faults, which were mostly inherited from basement faults and reactivated during the Zhuqiong movement (phase 2). Above these two structures, the faults are characterized by strike-slip faulting, which occurred in the Oligocene (phase 3). The overall geometry of the LFZ shows right-step dextral features in the PRM segment that are obviously segmented by NW–WNW-trending faults. Our results highlight the significant role of this ENE-striking fault system in the basin sub-basin (sag) formation on the northern continental margin of the SCS.

Investigation on hydrocarbon generation and expulsion potential by deep learning and comprehensive evaluation method: A case study of Hangjinqi area, Ordos Basin

The Hangjinqi area is a significant gas exploration area from the northern Ordos Basin, an important petroliferous basin in China. Although a considerable amount of achievements has been made in the natural gas exploration field, the controversy about the hydrocarbon generation characteristics of source rocks has raged unabated for ten years. In addition, few studies have systematically investigated hydrocarbon expulsion potential in the Hangjinqi area.In this paper, we adopted a series of new approaches to assess the hydrocarbon generation and expulsion potential of source rocks in Hangjinqi. Specifically, we analyzed the rock pyrolysis, kerogen composition, and biomarker data and applied Convolution Neural Network (CNN) in the field of deep learning to determine organic matter abundance, type, maturity and depositional environment. Then, two techniques, the hydrocarbon generation kinetics method and the hydrocarbon generation potential method, were implemented to obtain both the hydrocarbon generation and expulsion quantity. The results reveal that the new technique CNN is suitable for TOC prediction, and the performance is improved largely compared to traditional methods, e.g., Back Propagation neural network (BP) and △log R. Rock pyrolysis data, kerogen macerals and biomarker data reveal that the source rocks are gas-prone and dominated by type Ⅲ. By the integrating hydrocarbon generation potential method and hydrocarbon generation kinetics method, the hydrocarbon generation quantity of the study area is 20.35 × 1012m3. The results of the hydrocarbon potential method indicate that about 23.7 × 108t and 0.74 × 108t hydrocarbons were expulsed from coal and mudstone, respectively. According to comprehensive analysis, the hydrocarbon generation and expulsion quantities in the Hangjinqi area are extensive, indicating good prospects for natural gas exploration. These findings have significant implications for the understanding of natural gas resources potential and the distribution of favorable natural gas areas.

Sedimentary Environments of Cambrian–Ordovician Source Rocks and Ultra‐deep Petroleum Accumulation in the Tarim Basin

AbstractThe Tarim Basin is the only petroliferous basin enriched with marine oil and gas in China. It is presently also the deepest basin for petroleum exploration and development in the world. There are two main sets of marine Source Rocks (SRs) in the Tarim Basin, namely the high over‐mature Cambrian–Lower Ordovician (∊ –O1) and the moderately mature Middle–Upper Ordovician (O2–3). The characteristic biomarkers of SRs and oils indicate that the main origin of the marine petroleum is a mixed source of ∊ –O1 and O2–3 SRs. With increasing burial, the hydrocarbon contribution of the ∊ –O1 SRs gradually increases. Accompanied by the superposition of multi‐stage hydrocarbon‐generation of the SRs and various secondary alteration processes, the emergence and abnormal enrichment of terpenoids, thiophene and trimethylaryl isoprenoid in deep reservoirs indicate a complex genesis of various deep oils and gases. Through the analysis of the biofacies and sedimentary environments of the ∊ –O1 and O2–3 SRs, it is shown that the lower Paleozoic high‐quality SRs in the Tarim Basin were mainly deposited in a passive continental margin and the gentle slope of the platform, deep‐water shelf and slope facies, which has exhibited a good response to the local tectonic‐sedimentary environment. The slope of the paleo‐uplift is the mutual area for the development of carbonate reservoirs and the deposition of marine SRs, which would be favorable for the accumulation of petroleum. Due to the characteristics of low ground temperature, the latest rapid and deep burial does not cause massive oil‐cracking in the paleo‐uplift and slope area. Therefore, it is speculated that the marine reservoirs in the slope of the Tabei Uplift are likely to be a favorable area for deep petroleum exploration, while the oil‐cracking gas would be a potential reserve around the west margin of the Manjiaer Depression. Hydrocarbons were generated from various unit SRs, mainly migrating along the lateral unconformities or reservoirs and the vertical faults. They eventually brought up three major types of exploration fields: middle and lower Cambrian salt‐related assemblages, dolomite inner reservoirs and Middle and Lower Ordovician oil‐bearing karst, which would become the most favorable target of marine ultra‐deep exploration in the Tarim Basin.

Successive formation of secondary pores via feldspar dissolution in deeply buried feldspar-rich clastic reservoirs in typical petroliferous basins and its petroleum geological significance

Successive formation of secondary pores via feldspar dissolution in deeply buried feldspar-rich clastic reservoirs in typical petroliferous basins and its petroleum geological significance

Migration directions of crude oils from multiple source rock intervals based on biomarkers: A case study of Neogene reservoirs in the Bodong Sag, Bohai Bay Basin

Identifying oil origins and reconstructing oil migration directions are vital for oil exploration in continental petroliferous basins, but they become difficult and complicated when multiple source rock intervals are encountered. This is the case of the Neogene fluvial reservoirs in the Bodong Sag, Bohai Bay Basin, east China, which show significant spatial heterogeneity in oil charging. Here, we take the LK9-2 Structure in the southeastern Bodong Sag as an example to determine the potential factors controlling the oil migration directions from multiple source rock intervals. Total organic carbon contents, Rock-Eval pyrolysis results and biomarkers were applied to distinguish the major oil sources and trace the oil migration pathways. The first–second and third members of the Eocene Shahejie Formation and the third member of the Oligocene Dongying Formation in the Bodong Sag all showed high potential of generating oils for the overlying Neogene reservoirs. However, oil–source correlation by biomarkers revealed that the Neogene oils of the LK9-2 Structure were mainly derived from the third member of the Dongying Formation. Oils generated from the underlying Shahejie Formation were, however, mostly blocked by the thick mudstones of the Dongying Formation. The dimethyldibenzothiophenes and benzo[b]naphthothiophenes parameters, indicative of oil migration directions, showed the failure of lateral oil migration within the Neogene reservoir layers, which had been cut by active shallow normal faults. Therefore, the uppermost thick source rock intervals and abundant active shallow normal faults in the way of lateral oil migration were the two major factors that controlled the oil migration directions from multiple source rock intervals and probably accounted for the many uncharged traps in the Bodong Sag.