Search Results (88)

Defining the structure and evolution of multi-trend faults is critical for analyzing the accumulation of hydrocarbons in buried hills. Based on high-resolution seismic and drilling data, the structural characteristics and evolutionary mechanism of multi-trend faults were investigated in detail through the structural analysis theory and quantitative calculations of fault activity, allowing us to determine the implication that fault evolution exerts on hydrocarbon accumulation in the BZ19-6 buried hill. There are four kinds of strike faults developed on the buried hill: SN-, NNE-, NE–ENE-, and nearly EW-trending, which experienced the Mesozoic Indosinian, Yanshan, and Cenozoic Himalayan tectonic movements. During the Indosinian, the BZ19-6 was in a SN-oriented compressional setting, with active faults composed of SN-trending strike-slip faults (west branch of the Tanlu fault zone) and near EW-trending thrust faults (Zhang-peng fault zone). During the Yanshanian, the NNE-trending normal faults were formed under the WNW–ESE tensile stress field. Since the Himalayan period, the BZ19-6 buried hill has evolved into the rifting stage. In rifting stage Ⅰ, all of the multi-trend pre-existing faults were reactivated, and the EW-trending thrust faults became normal faults due to negative inversion. In rifting stage II, a large number of NE–ENE-trending normal faults were newly formed in the NW–SE-oriented extensional setting, which made the structure pattern more complicated. In rifting stage III, the buried hill entered the post-rift stage, with only part of the NNE- and NE–ENE-trending faults continuously active. Multi-trend faults are the result of the combination of various multi-phase stress fields and pre-existing structures, which have great influence on the formation of tectonic fractures and then control the distribution of high-quality reservoirs in buried hills. The fractures controlled by the NNE- and EW-trending faults have higher density and scale, and fractures controlled by NE–ENE trending faults have stronger connectivity and effectiveness. The superposition of multi-trend faults is the favorable distribution of high-quality reservoirs and the favorable accumulation area of hydrocarbon. Full article

Regional mudstone cap rock has an important influence on the oil and gas distribution of the oil source faults below it. Therefore, studying the influence of these mudstone cap rocks on the hydrocarbon distribution pattern is fundamental to understanding the oil and gas distribution of the lower generation and upper reservoir reservoirs in the Bohai Bay Basin. This study classified two types of hydrocarbon diversion from oil source faults: blockage diversion and seepage diversion. To locate them, we established a method to predict the areas with blockage diversion and seepage diversion separately by superimposing the sealing and leakage parts of the regional mudstone cap rock with the regions of the connected distribution of sand bodies and the favorable hydrocarbon transport sites of the oil source faults, respectively. We used this approach to predict the locations where hydrocarbons are diverted by the oil source faults under the regional mudstone cap rocks in the first and second sections of the Dongying Formation (E₃d_1-2) in the Liuchu area of the Raoyang Sag, Bohai Bay Basin. The results show that the regional mudstone cap rock’s blockage diversion occurs mainly in the south-central area of Liuchu, with a localized distribution in the northern part. The seepage diversion site is primarily located in the northeastern area and is also found locally in the west. Both diversions are beneficial for the accumulation of hydrocarbons from the source rocks of the first member of the Shahejie Formation (E₃s₁) to the upper second member of the Dongying Formation (E₃d_2U). The latter can also accumulate hydrocarbons in the Guantao Formation (N₁g). The results align with the hydrocarbon distribution, demonstrating the feasibility of our method to predict various oil source fault diversion sites under the regional mudstone cap rock. This prediction method offers valuable guidance for exploring the lower generation and upper reservoir hydrocarbon accumulations in hydrocarbon-bearing basins. Full article

Based on the WAVEWATCH III wave model, China’s National Marine Environmental Forecasting Center has developed an operational global ocean wave forecasting system that covers the Arctic region. In this study, in situ buoy observations and satellite remote sensing data were used to perform a detailed evaluation of the system’s forecasting results for 2022, with a focus on China’s offshore and global ocean waters, so as to comprehensively understand the model’s forecasting performance. The study results showed the following: In China’s coastal waters, the model had a high forecasting accuracy for significant wave heights. The model tended to underestimate the significant wave heights in autumn and winter and overestimate them in spring and summer. In addition, the model slightly underestimated low (below 1 m) wave heights, while overestimating them in other ranges. In terms of spatial distribution, negative deviations and high scatter indexes were observed in the forecasting of significant wave heights in semi-enclosed sea areas such as the Bohai Sea, Yellow Sea, and Beibu Gulf, with the largest negative deviation occurring near Liaodong Bay of the Bohai Sea (−0.18 m). There was a slight positive deviation (0.01 m) in the East China Sea, while the South China Sea exhibited a more significant positive deviation (0.17 m). The model showed a trend of underestimation for the forecasting of the mean wave period in China’s coastal waters. In the global oceanic waters, the forecasting results of the model were found to have obvious positive deviations for most regions, with negative deviations mainly occurring on the east coast and in relatively closed basins. There were latitude differences in the forecasting deviations of the model: specifically, the most significant positive deviations occurred in the Southern Ocean, with smaller positive deviations toward the north, while a slight negative deviation was observed in the Arctic waters. Overall, the global wave model has high reliability and can meet the current operational forecasting needs. In the future, the accuracy and performance of ocean wave forecasting can be further improved by adjusting the parameterization scheme, replacing the wind fields with more accurate ones, adopting spherical multiple-cell grids, and data assimilation. Full article

Free oil, rather than adsorbed oil, is the main contributor to shale oil production with current development technologies, and assessing oil contents in different occurrence states (adsorbed oil vs. free oil) is a critical component in evaluating the economics of shale wells and plays. Although various methodologies have been developed, there are still some fundamental issues in assessing the oil contents in different occurrence states in shale. In this study, a new method was developed to estimate the adsorbed and free oil contents in the Second Member of the Eocene Kongdian Formation (Ek₂) shales in Cangdong Sag, Bohai Bay Basin. This method combines the results of standard Rock-Eval pyrolysis and multi-step Rock-Eval pyrolysis with thin section petrography, X-ray diffraction for mineralogy, total organic carbon analyses, field emission scanning electron microscopy for pore morphology, and pore structure analyses by nitrogen physisorption and mercury intrusion porosimetry. Nine lithofacies were identified in a total of 50 shale samples, and the results show that the adsorbed and free oil are mainly contained in pores with diameters > 20 nm, and their contents are mainly controlled by organic matter abundance and thermal maturity of shales. While pore space volume influences the storage of shale oil, it is not a major determinant. Models of shale oil occurrence and its evolution are proposed, suggesting that the high S₁ contents of organic-rich and -fair shales, which the latter resulted from oil migration, are the most favorable exploration targets of Ek₂ shales. The findings of this study will help prioritize shale oil exploration targets in Ek₂ shales. Full article

The buried hills of the Archean metamorphic rocks in the Bozhong Depression of the Bohai Bay Basin are the main gas-bearing strata, with burial depths ranging from 4000 m to 5500 m. However, metamorphic rocks have internal structural characteristics, such as diverse mineral components, oriented arrangement of mineral particles, complex pore connectivity, variable crystal structures, orthogonal development of multiple sets of fractures, and uneven fluid filling. Compared with conventional reservoirs, they have obvious heterogeneity and anisotropy characteristics. Traditional rock physics modeling methods are no longer suitable for predicting the elastic and anisotropic parameters of metamorphic reservoirs. Therefore, we introduced a vector mixed random medium model to calculate the effect of the oriented arrangement of metamorphic rock minerals on the modulus of the rock matrix and introduced a metamorphic factor to describe the impact of metamorphic recrystallization and alteration metasomatism on the elastic modulus of the rock matrix. Practical applications have shown that the new, improved rock physics modeling method can better estimate the S-wave velocity and anisotropy parameters in wells compared to traditional rock physics modeling methods, providing a reliable basis for predicting fractured reservoirs in metamorphic rock at buried hills. Full article

The exploration and development of conventional oil and gas resources are becoming more difficult, and the proportion of low-permeability reservoirs in newly discovered reservoir resources has expanded to 45%. As the main focus of the oil industry, the global average recovery rate of low-permeability reservoir resources is only 20%, and most crude oil is still unavailable, so our understanding of such reservoirs needs to be deepened. The microscopic pore structure of low-permeability reservoir rocks exhibits significant complexity and variability; reservoir evaluation is more difficult. For elucidating the internal distribution of storage space and the mechanisms influencing seepage, we focus on the low-permeability sandstone reservoir of the Shahejie Formation, located on the northern slope of the Chenjiazhuang uplift, Bohai Bay. Employing a suite of advanced analytical techniques, including helium expansion, pressure pulse, high-pressure mercury intrusion (HPMI), and micro-computed tomography (micro-CT) scanning, we examined the main pore–throat size affecting reservoir storage and seepage in the reservoir at both the micrometer and nanometer scales. The results reveal that pores with diameters exceeding 40 μm are sparsely developed within the low-permeability reservoir rocks of the study area. However, pores ranging from 0 to 20 μm predominate, exhibiting an uneven distribution and a clustered structure in the three-dimensional pore structure model. The pore volume showed a unimodal and bimodal distribution, thus significantly contributing to the storage space. The main sizes of the reservoir in this study area are 40–80 μm and 200–400 μm. Micron-sized pores, while present, are not the primary determinants of the reservoir’s seepage capacity. Instead, coarser submicron and nano-pores exert a more substantial influence on the permeability of the rock. Additionally, the presence of micro-fractures is found to enhance the reservoir’s seepage capacity markedly. The critical pore–throat size range impacting the permeability of the reservoir in the study area is identified to be between 0.025 and 0.4 μm. Full article

The high exploration and development production capacity of the Jiyang Depression, Bohai Bay Basin, China in the early stage confirms the huge exploration and development potential of shale oil in the study area. Due to the complexity of the depositional mechanism in the study area, the distribution law of fine-grained sedimentary rocks is not well understood, which restricts further exploration breakthroughs. This paper comprehensively observes rock cores and thin sections, combines mineral components, Rock-Eval pyrolysis, rock-cutting logging and logging data to classify lithofacies, and clarifies the distribution law of various lithofacies. The research results show that, according to lithological characteristics, various lithofacies origins are classified into three categories: terrigenous, mixed, and endogenous sources, and six lithofacies types are distinguished: terrigenous low-organic-matter massive siltstone (LF1), terrigenous low-organic-matter massive mudstone (LF2), mixed-source medium-organic-matter massive mudstone (LF3), mixed-source medium-to-high-organic matter laminated-massive mudstone (LF4), mixed-source medium-to-high-organic-matter laminated mudstone (LF5), and endogenous-sourced medium-to-high-organic matter laminated limestone (LF6). The distribution of lithofacies in plane is symmetrical in the east–west direction and is characterized by a banded distribution; the distribution in profile shows a stable depositional process and a continuous depositional sequence. The various lithofacies depositional models have been summarized; the terrigenous input from the northern steep-slope zone has influenced the hydrodynamic conditions of the lake basin, significantly affecting the lithofacies depositional variations from the steep-slope zone to the deep-sag area. The geological evaluation of each lithofacies has been conducted; LF1 + LF4 + LF5 are classified as Class I—target reservoirs for shale oil development, while LF3 + LF6 are considered Class II—favorable reservoirs. The result of the study provide a reference for the classification of fine-grained sedimentary-rock facies and distribution characteristics, and the evaluation of shale-oil-reservoir sweet spots in graben lake basins. Full article

The Gudong area contains abundant petroleum resources. Previous studies have mainly focused on the extension structure in this area, with its strike-slip characteristics remaining poorly understood. In this study, the geometry of the strike-slip faults in the Gudong area was investigated using high-resolution 3D seismic reflection and drilling data, as were their associated releasing and restraining structures. Based on the profile’s flower structure and the plane’s horsetail splay pattern, the Gudong fault in the study area can be characterized as a dextral strike-slip. Three types of strike-slip fault-associated structures can be identified in the study area: (a) a restraining bend occurring in the right-stepping area of the S-shaped Gudong strike-slip fault, (b) a restraining bend identified in the left-stepping, overlapping zone of the Gudong and Kendong faults, and (c) a releasing bend seen in the extensional horsetail splay structure at the southern end of the Gudong fault. The restraining stress induced the formation of a fault-related open anticline, which led to a significant increase in fault sealing efficiency, thereby preserving an estimated 75.479231 million tons of oil and 15.28317145 billion cubic meters of gas. Conversely, releasing transtensional stress has compromised the effectiveness of the traps, preventing hydrocarbon retention. Consequently, oil and gas have migrated upward along the horsetail faults to the top of Cenozoic formations and have then dispersed. Full article

Oil content and the movability of shale oil are important indicators for the evaluation of continental shale oil. In recent years, the sandwiched shale oil in the fourth member of the Shahejie Formation in the Liaohe Western Depression area of the Bohai Bay Basin has shown great exploration potential, while the understanding of shale oil content and the movability of shale oil is weak. In this study, through a combination of core observations and experiments, we clarified the shale lithofacies types in the fourth member of the Shahejie Formation in the Liaohe Western Depression and explored the influencing factors of the characteristics in the oil-bearing and movability of shales in different lithofacies. The results of the study show that the organic matter content of the shale is high (TOC = 2.2–4.3%), but the maturity of thermal evolution is low (R_o = 0.38–0.55%), and the mineral component is dominated by clay minerals (30.3–72.7%), with quartz, feldspar, and other feldspar minerals developing secondarily. According to the content of organic matter, the mineral component, and the sedimentary structure, five types of lithofacies can be classified: organic-rich laminated clay-bearing felsic shale lithofacies (LS1), organic-rich laminated clay felsic mixed shale lithofacies (LS2), organic-rich layered clay felsic mixed shale lithofacies (LS3), organic-containing massive felsic-bearing clay shale lithofacies (LS4), and organic-containing massive clay felsic mixed shale lithofacies (LS5). The oil content of shale is mainly affected by the organic matter. The rate of increase in oil content of shale is fastest when the organic matter content is between 2 and 4%. The movability of shale oil is mainly controlled by the sedimentary structure, mineral component, and microscopic pore structure; the more the shale laminae is developed, the lower the clay content is, and the more the pore space is developed, the better the movability of shale oil is. Combined with the results of the shale oil content and mobility analysis in the study area, LS2 and LS3 are the dominant lithofacies in the fourth member of the Shahejie Formation in the study area, followed by LS1 >LS5 >LS4, so shale oil exploration should focus on the development of LS2 and LS3. Full article

In order to study the distribution pattern of oil and gas near the lower-source, upper-storage type of oil source faults in the hydrocarbon-bearing basins, a set of prediction methods favourable to oil and gas migration and accumulation were established by superimposing the parts of the oil source fault-associated traps, the contiguously distributed sand bodies and the lateral sealing position of faults. The trap associated with a fault can be determined by the fault’s convex part on the fault plane’s morphology map, the fault throw displacement curve and the intersection of faults on the structure map. The set of sand bodies can be determined by the sand-to-shale ration of the formation. The lateral sealing position of faults can be investigated by the shale content of the fault. This study is based on our case study of the Dazhangtuo Fault in the lower sub-member of the 1st member (Es₁^L) of the Shahejie formation in the northern Qikou Sag of Bohai Bay Basin. The results illustrate 4 fault nose traps formed by fault line deflection in the Es₁^L formation of the Dazhangtuo Fault, 2 each in the middle and eastern end. The Dazhangtuo Fault is favorable for oil and gas migration except at the eastern and western ends and the middle part of the fault. The fault-associated traps in the Es₁^L formation that are highly favorable for hydrocarbon migration and accumulation (overlapping site of associated traps and favorable location for oil and gas migration) are distributed in the eastern and central parts of the Dazhangtuo Fault. In contrast, those moderately favorable for hydrocarbon migration and accumulation (associated trap at a certain distance from the favorable location for oil and gas migration in the Dazhangtuo Fracture) are locally distributed in the east. Both traps are conducive to accumulating hydrocarbons from the underlying source rock in the Es₃ formation. Such observations are consistent with the current confirmed hydrocarbon distribution, thus validating the feasibility and accuracy of predicting the distribution of traps related to oil source faults favorable for hydrocarbon migration and accumulation, it can be used to guide the exploration of the lower-source, upper-storage type of hydrocarbon accumulations in the hydrocarbon-bearing basins. Full article

Since the “13th Five-Year Plan”, the exploration of large-scale structural oil and gas reservoirs in the Bohai oilfield has become more complex, and the exploration of igneous oil and gas reservoirs has become the focus of current attention. At present, igneous rock reservoir fluid identification methods are mainly based on the evaluation method of logging single parameter construction, which is primarily a qualitative identification due to lithology, physical property, and engineering factors. Accurate acquisition of interference logging data, and multi-parameter coupling and recording coupling methods are few, lacking systematic and comprehensive evaluation and analysis of logging data. Since conventional logging data in the study area have difficulty accurately and quickly identifying reservoir fluid properties, a systematic analysis was conducted of three factors: lithology, physical properties, and engineering, as well as a variety of logging parameters (gas measurement, three-dimensional quantitative fluorescence, geochemical, FLAIR, etc.) that can reflect fluid properties were integrated. Based on parameter sensitivity analysis, the quantitative characterization index FI of multi-parameter coupling fluid identification was established using the data from testing, sampling, and laboratory testing to develop the identification standard. The sensitivity analysis and optimization of characteristic parameters were carried out by integrating the data reflecting fluid properties such as gas surveys, geochemical data, and related logging data. Combined with gas logging-derived parameters and improved engineering parameters (the value of alkanes released by rock cracking per unit volume Cadjust, C1 abnormal multiple values, three-dimensional quantitative fluorescence correlation factor N), the fluid properties were identified, evaluation factors were constructed based on factor analysis, and fluid identification interactive charts were established. By analyzing test wells in the PL9-1 well area, the results of comparison test data are more reliable. Compared with conventional methods, this method reduces the dependence of a single parameter by synthesizing multiple parameters and reduces the influence of lithology, physical properties, and engineering parameters on fluid identification. It is more reasonable and practical. It can accurately and quickly identify the fluid properties of igneous rock reservoirs in the study area. It has a guiding significance for improving the accurate evaluation of logging data and increasing exploration benefits. Full article

As a hydrocarbon-rich depression within the Bohai Bay Basin, the Huanghekou Depression is a focal region for exploring hydrocarbons in the eastern China Sea. Previous studies have insufficiently examined the correlation between the enrichment of organic matter and the environments in which it is deposited. Herein, the hydrocarbon potential, palaeoclimate, sedimentary environment, organic matter sources, and organic matter enrichment of the source rocks of the Shahejie Formation in the Huanghekou Depression were investigated using organic and inorganic geochemical indicators. The organic matter type of the source rock in Huanghekou Depression’s Shahejie Formation was predominantly Type II, with a minor presence of Type III. Furthermore, the source rock had a poor-to-good comprehensive evaluation grade in E₃s_1–2, whereas E₂s₃ and E₂s₄ had medium-to-good comprehensive evaluations in their source rocks. In terms of maturity, E₃s₁ was in an intermediate position between the immature and mature stages and E₃s₂ and E₂s₃ were between the low-maturity and mature stages, whereas E₂s₄ transitioned into full maturity. Biomarkers and sensitive element indicators indicated that the organic matter in E₃s_1–2 was primarily derived from lower aquatic organisms and algae. This palaeoclimate was characterised by aridity, a water body containing saline and semi-saline water, and a strongly reducing environment resulting from water body stratification, leading to oxygen deficiency. The organic matter in E₂s₃ was primarily derived from aquatic organisms and algal inputs; these deposits were formed in a reduced environment characterised by relatively low salinity, ranging between semi-saline and freshwater conditions. The organic matter enrichment model of the Shahejie Formation was established based on sedimentary environment, palaeoclimatic, and organic matter source analyses, utilising E₃s_1–2 as preservation models and E₂s₃ as the productivity model. This study provides a basis for in-depth exploration and advancement of oil and gas reserves. Full article

It is beneficial in terms of the theoretical significance and application prospects to define the structure and reservoir development model of the lower Paleozoic unconformity in the Jiyang Depression of Bohai Bay Basin, China, for oil and gas exploration of unconformity in carbonate strata. Geological and geochemical evidence shows that a regional unconformity formed during the Huaiyuan Movement in the lower Paleozoic strata of the Jiyang Depression. Along the top of the regional unconformity between the Yeli Liangjiashan Formation and Fengshan Formation, various types of karst breccia have developed, showing prominent characteristics of development and vertical karst zonation. The paleokarst zone can be divided into the vadose zone and the underflow zone, and there are apparent differences between the two zones in terms of the mode of karst activity and type of reservoir space. Primitive sedimentary microfacies, dolomitization, and supergene karstification controlled the reservoirs of the Fengshan Formation and Yeli-Liangjiashan Formation. There are significant differences in the original physical properties due to the differences in the original sedimentary microfacies. The pore development of granular dolomite of high-energy beach facies has the best reservoir performance. In the later period, the superposition of dolomitization and supergene karstification resulted in apparent differences in karst development mode, development intensity, reservoir type, and reservoir physical properties. Among them, the granular dolomite reservoir has the best physical properties and has developed a cavity-type reservoir that has a planar distribution along an unconformity surface. Full article

Extralow-permeability reservoirs have emerged as a significant area of focus for CO₂ geological sequestration due to their stable subterranean structure and expansive storage capacity, offering substantial potential in addressing global climate change. However, the full extent of CO₂ geological sequestration potential within these extralow-permeability reservoirs remains largely unexplored. To address this gap, this paper utilizes the Shahejie Formation (Es1 member) of the Shuang 229 block in the Liaohe oilfield, Bohai Bay Basin, as a case study. This section is characterized by its abundant oil-gas reserves and serves as an exemplar for conducting experimental research on CO₂ storage within extralow-permeability reservoirs. The results demonstrate that the reservoir lithology of the Es1 member is fine sandstone and siltstone, with high compositional and structural maturity. Moreover, the average porosity is 14.8%, the average permeability is 1.48 mD, and the coefficient of variation of the reservoir is approximately 0.5, which indicates a low- to extralow-permeability homogeneous reservoir. In addition, the overburden pressure is >2.0 MPa, the fault can withstand a maximum gas column height of >200 m, and the reservoir exhibits favorable overburden and fault sealing characteristics. Notably, stepwise increasing gas injection in the Shuang 229-36-62 well reveals that the injected liquid CO₂ near the wellhead exhibits a relatively high density, close to 1.0 g/cm³, which gradually decreases to approximately 0.78 g/cm³ near a depth of 2000 m underground. The injected fluid changes into a supercritical state upon entering the formation, and the CO₂ injection speed is optimal, at 0.08 HCPV/a. According to these findings, it is predicted that the highest burial CO₂ volume via the injection of 1.5 HCPVs in the Wa 128 block area is 1.11 × 10⁵ t/year, and the cumulative burial volume reaches approximately 2.16 × 10⁶ t. This shows that the CO₂ sequestration potential of extralow-permeability reservoirs is considerable, providing confidence for similar instances worldwide. Full article

Lacustrine fine-grained sedimentary rocks in the Dongying Sag of the Bohai Bay Basin in China exhibit significant potential for hydrocarbon exploration. This study investigates the lithofacies types and sedimentary evolution of the Paleogene Shahejie Formation’s lower third member (Es3l) and upper fourth member (Es4u), integrating petrological and geochemical analyses to explore the relationship between lithofacies characteristics and sedimentary environments. The results show that the fine-grained sedimentary rocks in the study area can be classified into 18 lithofacies, with seven principal ones, including organic-rich laminated carbonate fine-grained mixed sedimentary rock lithofacies and organic-rich laminated limestone lithofacies. In conjunction with analyses of vertical changes in geochemical proxies such as paleoclimate (e.g., CIA, Na/Al), paleoproductivity (e.g., Ba), paleosalinity (e.g., Sr/Ba), paleo-redox conditions (e.g., V/Sc, V/V + Ni), and terrigenous detrital influx (e.g., Al, Ti), five stages are delineated from bottom to top. These stages demonstrate a general transition from an arid to humid paleoclimate, a steady increase in paleoproductivity, a gradual decrease in paleosalinity, an overall reducing water body environment, and an increasing trend of terrestrial detrital input. This study demonstrates that the abundance of organic matter is primarily influenced by paleoproductivity and paleo-redox conditions. The variations in rock components are predominantly influenced by paleoclimate, and sedimentary structures are affected by the depth of the lake basin. Special depositional events, such as storm events in Stage II, have significantly impacted the abundance of organic matter, rock components, and sedimentary structures by disturbing the water column and disrupting the reducing conditions at the lake bottom. The present study offers crucial insights into the genesis mechanisms of continental lacustrine fine-grained sedimentary rocks, facilitates the prediction of lithofacies distribution, and advances the exploration of China’s shale oil resources in lacustrine environments. Full article