Huimin Depression Research Articles

Target-based sedimentary diagenesis simulation and three-dimensional diagenesis evolution modeling

Deposition and diagenesis are important factors affecting the quality of oil and gas reservoirs. Previously reported diagenesis studies mainly involve qualitative analysis, such as the determination of diagenetic events and diagenetic evolution sequences and modeling of two-dimensional diagenetic evolution, with less effort devoted to quantitative numerical simulation and three-dimensional diagenetic evolution models. This study proposes a new method for target-based diagenesis simulation by integrating the discrete element method, the quartet structure generation set method, and morphological algorithms. This new hybrid method can quantitatively simulate the effects of mineral grain deposition, compaction, cementation, dissolution, and replacement. Since specific minerals can undergo specific diagenetic alterations through mineral labeling, the sequence and path of diagenesis can be predefined in this method. Taking the sandstone reservoir of Lower Member 3 of the Shahejie Formation in Linnan Sag, Huimin Depression, Bohai Bay Basin, East China as an example, the new simulation method used the constructed diagenetic evolution sequence based on thin section identification and geochemical analysis to systematically simulate deposition and diagenesis in the study area and to construct a three-dimensional diagenetic evolution model. The predicted porosity, permeability, and pore size distribution of the simulated digital rocks are in good agreement with the experimental values, which validates the high accuracy of the simulation method. Based on these three-dimensional multi-mineral evolution models, the evolution trends of porosity and permeability during the sedimentation and diagenesis process were elucidated, revealing the variation in reservoir quality in the studied area and indicating reservoir sweet spots. The constructed 3D diagenesis evolution models are widely applicable and can be used not only for permeability simulation but also for the study of electrical, acoustic, and mechanical properties of reservoirs.

Application of machine learning for evaluating and predicting fault seals: A case study in the Huimin depression, Bohai Bay Basin, Eastern China

Fault seal is of great significance for hydrocarbon migration, accumulation, and further hydrocarbon reservoir production. Approximate 32% petroleum resource is confirmed to be related to the faults. However, the existing fault seal evaluation methods based on statistical analysis cannot accurately predict fault seal which is influenced by multiple factors in a complex way. It is necessary to improve the fault seal evaluation methods for enhancing the exploration success rate. In this study, a new fault seal evaluation and prediction method based on decision tree (DT) and random forest (RF) is introduced. First, the original dataset was set by quantification and feature engineering work. Second, the nonlinear classification models for fault seal evaluation and prediction using a binary decision tree named the classification and regression tree (CART) were constructed and improved by overfitting calibration. Third, the random forest algorithm was selected as an ensemble learning method to improve the faut seal evaluation and prediction accuracy. Third, the evaluation metrics and cross-validation were used to evaluate the performance of the model. Finally, the validation test is applied for testing the reliability of the model. The result showed that among the 100,000 models constructed in this study, the DT best model could evaluate and predict the fault seal with a cross-validation accuracy of 80.60% after overfitting calibration by pruning. The best RF model showed the highest test accuracy of 86.54%, which is higher than that of the DT model. The models were used for predicting fault seals in another district in the Huimin Depression, and the prediction accuracy reached 90% and 95% for the DT and RF model, respectively. This study not only introduced a new method for fault seal evaluation and prediction, but also provided guidance for the application and development of machine learning in petroleum exploration and exploitation field and industry.

Base-Level Fluctuation Controls on Migration of Delta Lobes: A Case Study from the Paleogene Shahejie Formation in the Huimin Depression, Bohai Bay Basin, NE China

Sandbody distribution patterns and controls are the most important foundation for petroleum exploration and development, particularly in a lacustrine basin with rapid changes in the sedimentary environment. To provide sedimentologists and petroleum geologists around the world with an analogue for sandstone reservoir prediction, the sedimentary facies of the fourth member of the Shahejie Formation (Sha-4 Member) in the Huimin Depression of the Bohai Bay Basin were analyzed, and the sequence stratigraphic framework was established based on characteristics of spontaneous potential logs and lithology. According to the findings of this study, the Sha-4 Member’s sedimentary environment was dominated by delta front and shallow lake facies. Delta front sandbodies were discovered to retrograde before prograding again throughout the established profile. The Sha-4 Member in the Huimin Depression is divided into a third-order sequence (LSC1), which can be further divided into four fourth-order sequences (MSC1 to MSC4), corresponding to the four sub-members (S4-1 to S4-4). During the development of the MSC1 to MSC4 sequences, the delta depositional scale first decreased and then increased with the changing base level. The maximum flooding surface developed within the MSC3 sequence. The Sha-4 Member sequence model reveals that the deltas in the study area exhibit self-similarity, and delta sandbodies are primarily developed in the MSC1, MSC2, and MSC4, whereas mudstone is largely developed in the MSC3.

Evolution of abnormal pressure in the Paleogene Es3 formation of the Huimin Depression, Bohai Bay Basin, China

The evolution of abnormal pressure is of importance for the analysis of hydrocarbon migration and accumulation processes. However, paleo-pressure reconstruction is still a challenge with great uncertainty. In this study, the PVT simulation method and homogenization temperature-salinity method were used for abnormal pressure evolution analysis in the Huimin Depression, which is characterized by a complex distribution of abnormal pressure, including overpressure, normal pressure and underpressure. The origins of the abnormal pressure conditions were also analyzed to examine the rationality and reliability of paleo-pressure reconstruction by basin modeling and quantitative calculation. The results revealed different evolutionary processes for the paleo-pressure in the Central Deep-Sag Zone (CDSZ) and the Northern Tectonic Uplift Belt (NTUB). In the CDSZ, the abnormal paleo-pressure exhibited a rising stage during the late Oligocene owing to disequilibrium compaction. From the early to middle Miocene, the paleo-pressure decreased to hydrostatic pressure because of the elastic rebound of rocks and temperature reduction. From the late Miocene to middle Pliocene, the paleo-pressure rose again because of the deposition and hydrocarbon generation. From the late Pliocene to the present, the paleo-pressure decreased again owing to the termination of hydrocarbon generation and secondary migration of hydrocarbons. In the NTUB, the paleo-pressure remained hydrostatic without disequilibrium compaction during the late Oligocene, followed by an intense reduction process due to rock elastic rebound and temperature reduction owing to strong tectonic uplift from the early to middle Miocene. From the late Miocene to middle Pliocene, the paleo-pressure rose because of the deposition and hydrocarbon injection from the CDSZ. From the late Pliocene to the present, the termination of hydrocarbon generation, weakening of hydrocarbon injection from the CDSZ, and the gas diffusion led to the decrease of pressure again in the NTUB. This study reveals that the paleo-pressure experienced two rising and two falling stages in the CDSZ and finally is characterized from normal pressure to overpressure. The paleo-pressure in the NTUB experienced one rising and two falling stages and is currently characterized by underpressure. This study provides a new approach for assessing the paleo-pressure evolution based on multiple analytical methods and further contributes to research on hydrocarbon-accumulating dynamics and hydrocarbon-migrating processes.

Burial history and the evolution of hydrocarbon generation in Carboniferous-Permian coal measures within the Jiyang super-depression, China

In the Jiyang Sub-basin, Carboniferous-Permian (C-P) coal-measure source rocks have experienced complex multi-stage tectonics and therefore have a complex history of hydrocarbon generation. Because these coal measures underwent multi-stage burial and exhumation, they are characterized by various burial depths. In this study, we used the basin modeling technique to analyze the relationship between burial history and hydrocarbon generation evolution. The burial, thermal and maturity histories of C-P coals were reconstructed, including primary hydrocarbon generation, stagnation, re-initiation, and peak secondary hydrocarbon generation. The secondary hydrocarbon generation stage within this reconstruction was characterized by discontinuous generation and geographical differences in maturity due to the coupled effects of depth and a delay of hydrocarbon generation. According to the maturity history and the delay effect on secondary hydrocarbon generation, we concluded that the threshold depth of secondary hydrocarbon generation in the Jiyang Sub-basin occurred at 2,100 m during the Yanshan epoch (from 205 Ma to 65 Ma) and at 3,200 m during the Himalayan period (from 65 Ma to present). Based on depth, residual thickness, maturity, and hydrocarbon-generating intensity, five favorable areas of secondary hydrocarbon generation in the Jiyang Sub-basin were identified, including the Chexi areas, Gubei-Luojia areas, Yangxin areas, the southern slope of the Huimin depression and southwest of the Dongying depression. The maximum VRo/burial depth (%/km) occurred in the Indosinian epoch as the maximum VRo/time (%/100Ma) happened in the Himalayan period, indicating that the coupling controls of temperature and subsidence rate on maturation evolution play a significant role in the hydrocarbon generation evolution. A higher temperature and subsidence rate can both enhance the hydrocarbon generation evolution.

Attenuating gradient of residual stratigraphic pressure and its controls on hydrocarbon migration and accumulation

Abnormal stratigraphic pressure is highly significant for hydrocarbon migration and accumulation for the exploration and exploitation of exploratory fields. However, the relationship between abnormal pressure and hydrocarbon migration processes is difficult to characterize quantitatively. In this paper, a new parameter, the attenuating gradient of residual pressure (AGRP), which is defined as the variation in residual stratigraphic pressure over a unit distance in a certain direction, is introduced to characterize hydrocarbon migration forced by residual pressure and hydrocarbon accumulation influenced by fault seals in the Huimin Depression, Bohai Bay Basin. The AGRP against the geological background can be calculated by the formation pressure of the source region by equivalent depth method using well log data (sonic travel time/velocity and resistivity) formation pressure of hydrocarbon reservoirs by drill stem tests of 32 exploration wells. For the Huimin Depression, the calculation results of the third member of the Paleogene Shahejie Formation (Es3) reservoir interval show that the northern tectonic uplift belt (NTUB) and parts of the central deep sag zone (CDSZ) and southern slope belt (SSB) are characterized by stepped distributions of high AGRP values ranging from 1.2 to 2.5 MPa/km with developed faults. The other parts of the Huimin Depression are characterized by continuously distributed low AGRP values from 0.5 to 1.0 MPa/km. The AGRP is effective for characterizing and evaluating hydrocarbon migration and accumulation in structural hydrocarbon traps with AGRP values higher than 1.0 MPa/km, which indicates that these reservoirs are dominated by residual pressure as the main driving force. For these traps, oil and gas tend to migrate to the high-AGRP areas, which indicates a large driving force by residual pressure. Furthermore, the stepped distribution of the AGRP suggests a well-sealed fault and hence good preservation conditions for hydrocarbon accumulation. This study shows that the AGRP can characterize hydrocarbon migration and accumulation more precisely and hence provide guidance for petroleum exploration and exploitation, especially in rift petroliferous basins with abnormal pressure and developed faults.

Evolution characteristics of transtensional faults and their impacts on hydrocarbon migration and accumulation: A case study from the Huimin Depression, Bohai Bay Basin, eastern China

The study of transtensional faults is significantly important for analysing migration and accumulation of hydrocarbons in petroliferous basins. The purpose of this study is to present disparities in the temporal and spatial evolution of two boundary transtensional faults (northern Linshang Fault and southern Xiakou Fault) in the Huimin Depression by 2D structural restoration and quantitative calculations of fault activity. This paper also reveals the controls of transtensional faults on the migration and accumulation of hydrocarbons by considering the stress normal to the fault plane (P), the shale gouge ratio (SGR) of the fault zone, and models of migration pathways. The results show that the transtensional systems within the Huimin Depression were generated from the reactivation of basement faults under an oblique extensional stress field. The Linshang Fault linked two initially separated segments and then behaved as a single fault since the Ek period, whereas the Xiakou Fault retained significant three-segment growth properties during the Paleogene. During the hydrocarbon charging period, the weak activity and strong vertical sealing restricted the occurrence of vertical migration around the Xiakou Fault, while the relatively strong movement and weak vertical sealing resulted in multilayer hydrocarbon accumulations around the Linshang Fault. Meanwhile, the vertically closed fault with high SGR (>0.6) acted as barriers and trapped hydrocarbons on the lateral migration pathways, whereas the vertically closed fault with low SGR (<0.6) served as conduits for further lateral migration into structurally higher positions. The discovered hydrocarbons are concentrated around transtensional fault systems, and the divergent E-W-striking brush-shaped secondary faults trapped abundant hydrocarbons within the hanging wall, demonstrating the important controls of the transtensional faults on the migration and accumulation of hydrocarbons in the Huimin Depression.

Underpressure characteristics and origins in the deep strata of rift basins: A case study of the Huimin Depression, Bohai Bay Basin, China

Abnormal pressure is considered significant for the migration and accumulation of oil and gas. The purpose of this study is to present the lateral and vertical distribution of underpressure conditions in the Huimin Depression determined using the drill stem tests (DSTs) and the well log data. This paper also provides the origins of the underpressure both qualitatively and quantitatively, as well as the effects of the underpressure on the distribution of hydrocarbons. The results show two vertical underpressure units at depths of 1,500–2,500 m and 3,000–4,000 m with a pressure coefficient of 0.8–0.95. Laterally, the underpressure is mainly distributed in the Northern Tectonic Uplift Belt (NTUB) and Southern Slope Belt (SSB). The rock dilation and temperature reduction caused the pressure reductions of 3–4 and 1–3 MPa, respectively. The diffusion of natural gas plays a limited role on the underpressure. An analysis of the lateral seals of faults indicates that the underpressured regions developed in areas with faults with shale gouge ratio (SGR) values larger than 0.6. We propose that the widely distributed underpressure in the Huimin Depression is related to rock dilation, temperature reduction, and fault sealing. An analysis of hydrocarbon migration and reservoirs showed the pumping effect provided by the deficient pressure could make underpressured regions the primary targets for hydrocarbon accumulation, and in the Huimin Depression, underpressure might be more important than overpressure.

Comprehensive Provenance Analysis and Its Applications to Eocene Clastic Rocks in the Huimin Depression, Bohai Bay Basin, China

Clarification of the source of the Eocene sediments filling the Huimin depression provides significant support for current and future oil and gas exploration in the Bohai Bay Basin, China. A comprehensive assessment of sediment provenance based on sandstone petrography, heavy mineral assemblages, seismic reflection data, and distribution of sandstone bodies of the Shahejie Formation (Es2) to the Dongying Formation (Ed) productive interval based on both its macroscopic and microscopic provenance aspects. This method of analysis has the advantages of easy data acquisition, high accuracy, strong flexibility, wide application range, and making the analysis of sedimentary provenances more systematic. Comprehensive analysis of the Huimin depression, Bohai Bay Basin has revealed further that the origin of the Eocene second member of the Shahejie Formation (Es2) to the Dongying Formation (Ed) provenance system was derived from the Linfanjia high, the Chengning uplift, and the Luxi uplift.

Overpressure Generation Mechanisms and Its Distribution in the Paleocene Shahejie Formation in the Linnan Sag, Huimin Depression, Eastern China

The Linnan Sag is one of the main oil-producing units in the Huimin Depression, Eastern China, and the pore pressure gradients obtained from drill stem tests (DSTs) range from 9.0 to 16.0 MPa/km. Uncertainty about the origin and distribution of abnormally high pressures in the Linnan Sag has led to different interpretations of hydrocarbon accumulation and resource assessments, and it interferes with safe drilling. In the Linnan Sag, mudstone compaction curves are substantially affected by several non-compaction factors, and the normal trend of the compaction curve is difficult to determine. The determination of the origin and distribution of overpressure in the Linnan Sag is a challenge. In this study, the factors that may affect mudstone compaction—such as the shale volume, higher calcareous, and organic matter content—were carefully examined and processed. The pressures in the mudstones were estimated by the corrected mudstone compaction curves, which were compiled from acoustic, density, and neutron logs, and calibrated using DST and mud weight data. The log response–vertical effective stress and acoustic velocity-density crossplots were used to identify the mechanisms that generate overpressure. The comprehensive compaction curve shows that the mudstones in the overpressured layer exhibit clear disequilibrium compaction characteristics. The logging response crossplots demonstrate that those overpressured points were consistent with the loading curve. The findings suggest that, the fundamental mechanism resulting in overpressures is the disequilibrium compaction of thick Paleocene mudstones. Hydrocarbon generation and vertical transfer of overpressure may be the main unloading mechanisms, which corresponds to the overpressure points that deviate from the loading curves. Since organic matter cracking may occur in formations at depths greater than 4000 m (Ro &gt; 1.0%), the contribution of hydrocarbon generation to overpressuring is expected to be limited. The transfer of overpressure through opening faults is therefore considered to be the main cause of higher overpressure in local sandstones. The overpressures in the mudstones are characterized by a gradual decrease from the center to the margin in the Linnan Sag. The pressure in the isolated sand bodies are generally similar to that in the surrounding mudstones, whereas it can be lower or higher when the overpressure in the sand bodies are vertically transferred by faults to other pressure systems. The results of this analysis provide an indication of the magnitude, mechanism, and distribution of overpressure in the Linnan Sag. This insight can be used to guide further exploration of the Linnan Sag and similar geological basins.

Application of biomarkers to petroleum migration in the Linyi fault area, Huimin Depression, Bohai Bay Basin, China

A geochemical investigation was carried out on 32 crude oil samples to investigate the origin of the oil and to trace the migration direction in the Linyi fault area, Huimin Depression, Bohai Bay Basin, China. The oils, which were characterized by low gammacerane content and a dominance of C27 over C29 regular steranes, originated from the source rock of the third member of the Shahejie Formation (Es3) in the Linnan Sag. A sequential charge of low- and high-maturity oils from the Es3 source rocks resulted in a decrease in oil maturity in the migration direction. The petroleum migration direction in the footwall of the Linyi fault was northward, away from the fault, and the migration direction at the southwest end (in the hanging wall) of the Linyi fault was westward, along the fault, as evidenced by lateral gradients of biomarker parameters of various maturity, density, and viscosity.

惠民凹陷商河油田商三区沙二下低渗透储层特征

惠民凹陷商河油田商三区沙二下低渗透储层特征

Factors controlling reservoir properties and hydrocarbon accumulation of lacustrine deep-water turbidites in the Huimin Depression, Bohai Bay Basin, East China

Lacustrine deep-water turbidite plays are a novel area for exploration in the Huimin Depression, Bohai Bay Basin. Turbidites in the Shang 847 block, a typical turbidite play in the Huimin Depression, provide an opportunity to study the factors controlling the reservoir properties and hydrocarbon accumulation in lacustrine turbidite sandstones. The reservoir quality of turbidite sandstones (very fine-grained, moderately to well sorted, mainly lithic arkose) in this study area are mainly controlled by the distribution patterns of carbonate cements and pseudomatrix. Significant inverse relationships exist between the volume of carbonate cement and both porosity and permeability of the turbidite sandstones. Carbonate cement is located preferentially near the margins of the sandstone bodies. Sandstones with distance from the sandstone–mudstone contact surface less than 0.7 m or with thickness less than 1.2 m are commonly tightly cemented (carbonate cement >15%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The source of carbonate cement was most likely external, probably derived from the surrounding mudstone. Most pore-filling carbonate cements occurred during late diagenesis at burial depths greater than 2200 m. The petrophysical properties of turbidites have a positive relationship with the content of kaolinite and chlorite, but have a negative relationship with the content of illite. 2-D and 3-D reconstructions of non-oil bearing and oil-bearing layers indicate that dissolution of carbonate cement, feldspars and unstable rock fragments was more developed in oil-bearing layers than in non-oil bearing layers and hance oil-bearing layers have higher porosity and larger pore sizes. Petrophysical property appears to have a significant effect on the hydrocarbon accumulation in the turbidite sandstones. Sandstones with porosities lower than 9% and/or permeabilities lower than 0.78 mD are not prone to contain oil.

Study on Fault Activity in Linnan Area of Huimin Depression, Bohai Bay Basin

Based on the analysis of growth index, fault throw and fault activity rate, we find the method of fault activity rate integrates advantages of other methods which avoids the influence of erosion and could carry out comparison among fault activities of different geological times. We optimize the method of fault activity rate to analyze the characteristics of fault activities in Linnan area and the results show: the main direction of the faults in Linnan area is nearly NEE-trending and most of the faults have two larger activity periods. It acts intensively in the period of Es2 and Ed and weakens in the period of Es1 and Ng. There is a small comeback in the period of Nm at last. We conduct the force analysis of this area based on stress ellipsoid and find that the stress state agrees well with the regional geological background. The evolution of faults is impacted by the subduction of the Pacific plate and the compression of the Indian Ocean plate.

Tectonics and mechanisms of uplift in the central uplift belt of the Huimin depression

The Huimin (惠民) depression is a third-level tectonic element of the Bohai (渤海) Bay basin in eastern China. The central uplift belt is the most important oil and gas accumulation zone in the depression, but the lack of adequate geological studies in the area has greatly hindered exploration

Diagenesis and reservoir quality of the fourth member sandstones of Shahejie formation in Huimin depression, eastern China

Petrographic analysis combined with various techniques, such as scanning electron microscopy and X-ray diffraction, was used to assess the timing of growth and original mineral cements, the controls on reservoir and reservoir quality of the fourth member sandstones of Shahejie formation (Es4). The Es4 sandstones are mostly arkose and lithic arkose, rarely feldspathic litharenite, with an average mass fraction of quartz 51.6%, feldspar 33.8% and rock fragments 14.6% (Q51.6F33.8R14.6). They have an average framework composition (mass fraction) of quartz 57.10%, K-feldspar 5.76%, sodium-calcium feldspar 13.00%, calcite 5.77%, dolomite 5.63%, siderite 0.95%, pyrite 0.30%, anhydrite 0.04%, and clay mineral 11.46%. The diagenentic minerals typically include kaolinite, illite-smectite (I/S), illite, chlorite, authigenetic quartz and feldspar, and carbonate and pyrite. Es4 sandstone has undergone stages A and B of eodiagenesis, and now, it is experiencing stage A of mesodiagenesis. Reservoir quality is predominantly controlled by the mechanical compaction, for example, 45.65% of the original porosity loss is related to compaction. The original porosity loss related with cementation is only 26.00%. The reservoir quality is improved as a result of dissolution of feldspar, rock fragment and so forth. The porosity evolved from dissolution varies from 3% to 4%.

Remaining oil distribution in Ng 33 bottom water reservoir of Lin 2-6 fault-block in Huimin depression and potential tapping in horizontal well

Oil reservoirs with secondary bottom water in Ng 3 3 members (in Guantao formation, Paleogene system) of Lin2-6 fault block in Huimin depression (Bohai Bay Basin) have entered the late stage of ultra-high water-containing-exploitation. Oil exploitation from vertical wells is becoming more and more inefficient. The reservoir type, with water displacing oil and the remaining oil distribution are specifically studied in order to improve the efficiency of the recovery ratio. An integrated scheme for adjusting horizontal wells has been designed and the key technique of the scheme optimized. The study shows that: 1) the positive rhythm of fluvial depositional features is the internal cause of the flooding of oil reservoirs while water injection, injection-production patterns and accumulative petroleum production are the external causes; 2) oil-water driving patterns have transferred from edge water advancing to bottom-water-coning; distribution of the remaining oil mainly concentrates in the upper rhythm and top of the middle rhythm in Ng 3 3 members; 3) a great deal of remaining oil is enriched in high positions of faults, in axes of tiny structures, in stagnation areas among water-injection wells and oil-wells and in tectonic saddle areas with sparse wells. Compared with vertical wells, horizontal wells have advantages such as high recovery, high off-take potential, high critical output, large controlling areas and long time of bottom-water breakthrough.

Composition and Provenance of Sandstones and Siltstones in Paleogene, Huimin Depression, Bohai Bay Basin, Eastern China

This study was conducted to distinguish the compositions and provenance of sandstones and siltstones in the E k 1–E s 3 members of Huimin depression. The samples have been analyzed for petrographic, major element and selected trace element compositions (including REE). The results show that the sandstones from the first member of Kongdian Formation (E k 1) have higher quartz compositions than those from the fourth member (E s 4) and the third member (E s 3) of Shahejie Formation. The alkali feldspar/plagioclase ratio in the A-CN-K diagrams decreases in the order E k 1>E s 4>E s 3, which suggests that the E k 1 member had a more alkali feldspar-rich granitoid source and more intense weathering of the source than the E s 4 and E s 3 members. The mineral distributions in the A-CN-K diagrams also indicate that the sandstones and siltstones in the three members underwent K-metasomatism. Extrapolation of the sandstones and siltstones back to the plagioclase-alkali feldspar line in the A-CN-K diagram suggests a high average plagioclase to alkali feldspar ratio in the provenance (tonalite to granite). In addition, the chemical index of weathering (CIW) and chemical index of alteration (CIA) parameters of the sandstones and siltstones suggest that the weathering of the first cycle material was intense, and the CIW decreases in the order E k 1>E s 4>E s 3. Trace element ratios suggest all the sedimentary rocks were mostly derived from granitoids. Elemental ratio plots (e.g., Th/Sc vs. Eu/Eu*) of sandstones and siltstones suggest a mix of a granodiorite-tonalite source as a source of the sandstones and siltstones. The sandstones and siltstones of E s 3 and E s 4 members also contain higher Eu/Eu* and lower Th/Sc ratios than the sandstones and siltstones of E k 1 member. As is consistent with the petrography, it suggests that the sandstones and siltstones of E s 3 and E s 4 members are derived from a source with less granite and more granodiorite-tonalite than the sandstones and siltstones of E k 1 member.

Theoretical Calculation Model of Heat Transfer for Deep‐derived Supercritical Fluids with a Case Study

Abstract Based on a set of equations established by Duan et al. (1992, 1996) for a geofluid system H2O‐CO2‐CH4(‐N2), a formula is obtained to calculate the heat changes. Combining the geological T‐P conditions (geothermal gradients and lithostatic and hydrostatic pressures), the enthalpy of some typical geofluids is figured out. Then the principles of heat transfer of deep‐derived supercritical fluids are discussed. The result shows that deep‐derived geofluids can bring a large amount of thermal heat and release most heat to the shallow surroundings as they move up, because the molar enthalpies vary very greatly from the deep to shallow, increasing with the increases of T and P. Generally, more than tens of kilojoules heat per molar can be released. Furthermore, the molar enthalpy is affected by the compositions of the geofluids, and the molar enthalpy of CO2, CH4, or N2 is greater than that of H2O, being twice, more than twice, and about 140% of H2O, respectively. Finally, a case study is conducted by investigating a source rock sequence affected hydrothermally by magmatic fluids in the Huimin depression of Shengli Oilfield. The thermal heat calculated theoretically of the fluids related to a diabase intrusion is quite large, which can increase the temperature near the diabase to about 300°C, and that can, to some extent, account for the abnormal rise of the vitrinite reflectance, with the highest of about 3.8% (Ro).

Formation conditions and distribution regularities of oil-gas pools in tertiary volcanic rocks in western Huimin depression, Shandong province

The formation conditions and distribution regularities of oil-gas pools in volcanic rocks in western Huimin Depression have been studied in terms of geologic, seismic and well logging information. This paper discusses the types and lithofacies, development and distribution of Tertiary volcanic rocks in the area. The results demonstrate that volcanic activity occurred mainly during the period from the Sha-4 stage to the Guantao episode, i.e., before the oil-generating period (before the end of the Guantao episode and the Minghuazhen episode). The activity did not destroy oil and gas formation and accumulation, but was favourable for the concentration of organic matter and its conversion to hydrocarbons; besides, volcanic rocks can serve as reservoir rocks and cap rocks, playing a role very similar to that of a syndepositional anticline. The volcanic rocks are distributed near the margins of the oil-generating depression; there are many secondary interstices in the rocks, which are connected with each other. These are the leading conditions for the formation of oil-gas pools in volcanic rocks. The formation of volcanic rocks in high structural levels before the main oil-generating period and their self-sealing or good combination with other cap rocks are important factors for forming volcanic rock-hosted oil and gas pools. The oil-gas pools associated with volcanic rocks in western Huimin are mainly distributed around the deep oil-generating depression, in the central uplift or the high structural levels on the margins of the depression. In particular, the sites where several faults cross are usually locatons where high-yielding oil-gas pools in volcanic rocks are concentrated.