Nanpu Sag Research Articles

Organic geochemical characteristics and shale oil potential of the middle Eocene early-mature shale in the Nanpu Sag, Bohai Bay Basin, Eastern China

The decline of proven conventional petroleum resources in the shallow portions of the Nanpu sag has shifted attention to the exploration of deep unconventional oil and gas resources there, especially the shale oil resources in the middle Eocene shales of the Shahejie Formation (MES shales). In this study, to assess the oil potential of the MES shales, we carried out a systematical geochemical and basin modeling characterization. The results show that the MES shales have low maturity and are at the early stage of hydrocarbon generation, with a mean vitrinite reflectance of 0.64% and low ratio of C27 18α(H)-22, 29, 30-trisnorneohopane to C27 17α(H)-22, 29, 30-trisnorhopane (0.44–1.18). The MES shales contain abundant organic matter (OM), with an average total organic carbon content of 2.21 wt %. Biomarker analyses show that the OM in the MES shales derived mainly from floating macrophyte and aquatic algae, microalgae and bacteria. The sapropelinite group in the MES shales is predominant in the organic macerals, and the kerogen is sapropelic and dominated by types I and II1. Biomarker analyses also reveal that the MES shales were deposited in the stratified water column as suggested by the presence of gammacerane, under relatively warm and wet climatic conditions. The anoxic conditions built up in the water column facilitated the OM preservation, although slight microbial degradation resulted in relatively high carbon preference index values. Modeling results based on geochemical data and basin analyses show that considerable quantities of hydrocarbons remain in the low-maturity MES shales. The preliminary estimate of the quantity of shale oil resources in the Gaoliu area of Nanpu sag is approximately 1.78 × 108 t. Nanpu sag have good shale oil potential, and shale oil exploration may be more feasible for MES shales, especially in the context of in-situ heating technology.

Fan-delta facies architecture, morphological evolution and sediment delivery in the Oligocene Dongying Formation of the Nanpu Sag, Bohai Bay Basin, China

Core, well log and seismic data are used to investigate relationships between fan-delta facies architecture, basin margin morphology and sediment transportation into a deep-lacustrine environment of the Dongying Formation of Nanpu Sag, Bohai Bay Basin. The study interval is subdivided into two fan-delta dominant, third-order sequences of Stratasequence Paleogene Dongying Formation 1 (SQEd 1) (younger) and Stratasequence Paleogene Dongying Formation 2 (SQEd 2) (older). Fan-delta growth occurred in two stages with changing of facies architecture and morphology. During the early stage (SQEd 2), the facies architecture is characterised by smaller and thin, channelised deposits, an extended mouth bar (delta-front sandy deposits) and slump/slides/flood turbidite dominated sandy deposits in the prodelta. However, during the late stage (SQEd 1), the facies architecture is characterised by extended and thicker channelised deposit-dominated area, a local mouth bar (delta-front sandy deposits) and slump/slide-dominated sandy deposits in the prodelta. From the early to late stage, the delta morphology also changed with an upward increase in the delta-plain areal extent and delta-front gradient. Facies architecture variations indicate differences in sediment dispersal. The upward thickening and extending delta plain implies that more sediment was trapped in the proximal area owing to sufficient accommodation space generated by increasing boundary fault displacement. The upward increasing delta-front gradient resulted in differences in the type of prodelta/deep-lacustrine sandy deposits, while grainsize variations of the delta-front deposits affect the prodelta/deep-lacustrine sandy deposits. Boundary fault growth occurred with upward increasing displacement and length with the result that sediment supply outpaced accommodation-space creation and controlled the facies architecture changes. KEY POINTS A two-stage fan delta developed with changing facies architecture is analysed. Facies architecture controlled fan-delta morphology with sediment transport into a deep-lacustrine area. Faults control the facies architecture and sand-rich deposit distribution.

Characteristics and origin of oil and gas in the Nanpu sag, Bohai Bay Basin, China: Insights from oil-source correlation and source rock effects

The Nanpu sag is a typical petroliferous area in the Bohai Bay Basin. Crude oil density and viscosity, natural gas components and biomarker chemistry of crude oil, and shale sample extracts were analyzed to determine the characteristics and the origin of oil and gas and the effects of source rock on oil and gas distribution. The discovered heavy oil present in the shallow layers of the Liuzan, Gaoshangpu, and Laoyemiao regions are a product of biodegradation and oxidation. The crude oil samples from the offshore locations are low density and viscosity, indicating good preservation conditions. Biomarker compositions indicate that the crude oils can be divided into four types: A, B, C, and D. Both type A and D oils were sourced from the third member of the Shahejie Formation. Type A oil is primarily distributed in the Liuzan and Gaoshangpu regions, whereas type D oil is chiefly distributed in the nos. 1, 2, 5, and Beipu structural belts (SBs). Type B oil, derived from the third member of the Dongying Formation, is primarily distributed in the Laoyemiao, Gaonan, and Liunan SBs. The type C oil is primarily derived from the first member of the Shahejie Formation and is distributed in the Beipu and nos. 1–4 SBs. The hydrocarbons are primarily distributed in the regions where the thick source rocks interact with faults. The discovered natural gas in the Nanpu sag is primarily observed as dissolved gas in oil and free gas.

Characteristics and Genesis of the Es1 Productive Sandstone Reservoir (Paleogene), Nanpu Sag, East China

AbstractThe Shahejie Formation is a fundamental rock unit for hydrocarbon exploration and production in the Nanpu Sag, Bohai Bay Basin. Methodology including thin sectioning, core observations, fluorescence, scanning electron microscopy, cathodoluminescence, fluid inclusion, laser scanning confocal microscopy and geochemical analysis (C, O isotopes) were all utilized to investigate the reservoir characteristics and origin of the Es1 Sandstone. Thin section study showed that the reservoir rock consisted of feldspathic litharenite and lithic arkose. The reservoir pores are categorized as intergranular pores, fracture pores, dissolution pores and intergranular cement dissolution pores. The studied sandstone had good porosity (0.05%–35%) and permeability (0.006–7000 mD). The Es1 reservoir is classified as a fractured reservoir, a primary intergranular pore‐associated reservoir and a dissolution reservoir. Deposition, diagenesis and tectogenesis are the main factors that played important roles in the development of the reservoir. Sedimentation is the foundation and assumption for reservoir development, but the effective reservoir is primarily controlled by primary pores, fractures, lithofacies, tectonic elements and dissolution pores. Moreover, compaction, fracture filling and cementation were the primary sources of reservoir densification. The reservoir was progressively formed through the influence of different geological and diagenetic events. The present study provides significant information and references for hydrocarbon exploration and development in the Nanpu Sag.

Geology and development of geothermal field in Neogene Guantao Formation in northern Bohai Bay Basin: A case of the Caofeidian geothermal heating project in Tangshan, China

Taking the Gaoshangpu-Liuzan geothermal field in the Nanpu sag of the Bohai Bay Basin as the research object, this paper discusses the geological conditions and potential of the geothermal resources of the Guantao Formation in the study area, and introduces the development practice of geothermal energy heating in Caofeidian. The average buried depth of the Guantao Formation is 1500–2500 m, the lithology is dominated by sandy conglomerate, and the average thickness of thermal reservoir is 120–300 m. The average porosity of thermal reservoir is 28%–35%, the permeability is (600–2000)×10−3 μm2, and the temperature of thermal reservoir is 70–110 °C. The formation has total geothermal resources of 13.79×1018 J, equivalent to 4.70×108 t of standard coal. Based on a large amount of seismic and drilling data from oil and gas exploration, this study carried out high quality target area selection, simulation of sandstone thermal reservoir, and production and injection in the same layer. The geothermal heating project with distributed production and injection well pattern covering an area of 230×104 m2 was completed in the new district of Caofeidian in 2018. The project has been running steadily for two heating seasons, with an average annual saving of 6.06×104 t of standard coal and a reduction of 15.87×104 t of carbon dioxide, achieving good economic and social benefits. This project has proved that the Neogene sandstone geothermal reservoir in eastern China can achieve sustainable large-scale development by using the technology of “balanced production and injection in the same layer”. It provides effective reference for the exploration and development of geothermal resource in oil and gas-bearing basins in eastern China.

Quantitative evaluation of lateral sealing of extensional fault by an integral mathematical-geological model

To evaluate the lateral sealing mechanism of extensional fault based on the pressure difference between fault and reservoir, an integral mathematical-geological model of diagenetic time on diagenetic pressure considering the influence of diagenetic time on the diagenetic pressure and diagenetic degree of fault rock has been established to quantitatively calculate the lateral sealing ability of extensional fault. By calculating the time integral of the vertical stress and horizontal in-situ stress on the fault rock and surrounding rock, the burial depth of the surrounding rock with the same clay content and diagenesis degree as the target fault rock was worked out. In combination with the statistical correlation of clay content, burial depth and displacement pressure of rock in the study area, the displacement pressure of target fault rock was calculated quantitatively. The calculated displacement pressure was compared with that of the target reservoir to quantitatively evaluate lateral sealing state and ability of the extensional fault. The method presented in this work was used to evaluate the sealing of F1, F2 and F3 faults in No.1 structure of Nanpu Sag, and the results were compared with those from fault-reservoir displacement pressure differential methods without considering the diagenetic time and simple considering the diagenetic time. It is found that the results calculated by the integral mathematical-geological model are the closest to the actual underground situation, the errors between the hydrocarbon column height predicted by this method and the actual column height were 0–8 m only, proving that this model is more feasible and credible.

Diagenetic facies and reservoir porosity evaluation of deep high-quality clastic reservoirs: A case study of the Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, China

Petrological analysis, thin-section observation and laboratory analysis data were selected to systematically study the physical and diagenetic features of the first member of the Paleogene Shahejie Formation (Es1) in the No. 3 structural belt of the Nanpu Sag, Bohai Bay Basin. The intensities of different diagenetic processes were determined, the diagenetic evolution sequence was reconstructed, the typical diagenetic facies were identified and the effects of different diageneses on the reservoir were quantitatively analyzed. The results show that the main intergranular fillings include authigenic-quartz, quartz secondary enlargement, clay minerals, carbonate cement and matrix. The pore types include intergranular porosity, dissolution porosity and microfractures. The reservoir has experienced compaction, early cementation, dissolution and late cementation, among which compaction is the most important porosity reducer. Compaction was the main diagenetic process involved in porosity reduction, accounting for about 24.4% of the loss of thin-section porosity. The dissolution process clearly improved the porosity, increasing thin-section porosity by 2.7%. Five diagenetic facies were identified on the basis of petrographic analyses, namely, (a) strongly compacted-weakly cemented-weakly dissolved facies; (b) weakly compacted-strongly cemented-weakly dissolved facies; (c) moderately compacted-moderately cemented-weakly dissolved facies; (d) strongly compacted-weakly cemented-moderately dissolved facies; and (e) strongly compacted-weakly cemented-strongly dissolved facies. According to the analysis of diagenesis intensity, the porosity evolution model of various diagenetic facies was reconstructed, and the reservoir quality of various diagenetic facies was quantitatively predicted. The reservoir quality of different diagenetic facies clearly changed with depth. The best reservoir quality was in strongly compacted–weakly cemented–strongly dissolution facies, which have good sorting, contain a large amount of feldspar and soluble debris, and are mainly developed in the main part of the river channel. Our study can provide a reference for the subsequent exploration and development of deep petroleum systems.

Characterization of micropore structure of a middle to deep clastic reservoir: The oligocene reservoir in the Nanpu Sag, Bohai Bay Basin, China

In this paper, the Oligocene reservoirs in the Nanpu Sag of the Bohai Bay Basin are studied by scanning electron microscopy (SEM), thin section observation, XRD, nuclear magnetic resonance (NMR), and mercury injection. The purpose is to judge the microscopic pore structure of the reservoir in the study area through: 1) Combining nuclear magnetic resonance technology with fractal dimension to analyze the pore structure characteristics of sandstone; 2) using mercury injection experiments to judge the connectivity of pore throats; and 3) combining petrophysical properties-NMR-fractal dimension-mercury injection to predict reservoir quality. The results show that the sandstones of the Ed3 and Es1 members in the Nanpu Sag of the Bohai Bay Basin have good physical properties, medium porosity (5.2%–18.7%, average 11.70%) and permeability (0.08mD-111mD, average 22.68mD). Using the T2 spectrum, the fractal dimension of the bound fluid pore and the fractal dimension of the movable fluid pore are determined. The movable fluid pore is more complicated than the bound fluid pore. There is a connection between fractal dimension and mineral composition. High clay mineral content leads to a complex pore network, and the larger the fractal dimension, the more complex the pore shape and the lower the permeability.

Evaluation method for low- to ultralow-permeability reservoirs based on pore-throat structure: A case study in the eastern Nanpu Sag, Bohai Bay Basin, China

The pore-throat structure of low- to ultralow-permeability reservoirs is complex, causing the permeability to vary greatly under similar porosity conditions. Moreover, the pore-throat structures are the key factors that controled the physical properties of such kind of reservoirs. Therefore, conventional reservoir evaluation methods can hardly meet the research needs of low- to ultralow-permeability reservoir exploration and development. We have conducted our research on Paleogene Shahejie and Neogene Dongying low- to ultralow-permeability reservoirs in the eastern Nanpu Sag of the Bohai Bay Basin to address this issue. Cores, thin sections, and scanning electron microscopy were used to analyze the pore-throat structures to determine the characteristics of low- to ultralow-permeability reservoirs, and a new parameter for evaluating low- to ultralow-permeability reservoirs is developed. The results of this research show that primary pores, secondary pores, and microfractures are developed in the study area and that the pore-throat shape is mainly flaky or curved flaky. The microscopic pore-throat structure controlled the reservoir physical properties and fluid mobility of these reservoirs, the permeabilities of these reservoirs are dependent on the pore throats, and the correlation between connected pores and permeability is strong. Based on the analysis of the pore-throat structure, as well as the maximum mercury saturation (Smax) and the residual mercury saturation (Sr) at the maximum pressure and the minimum pressure obtained by the mercury injection test, an evaluation of the reservoir by using the mobility parameter of fluid (Δfm = Smax-Sr) is proposed, and the pore-throat radius R15 obtained by the mercury intrusion experiment has the best correlation with the fluid mobility parameters. The mobility parameters of fluid can effectively improve the accuracy of logging interpretation of low- to ultralow-permeability reservoirs and provide a scientific basis for the scale stimulation and effective development of low- to ultralow-permeability reservoirs.

Seismic resolution enhancement by the Curvelet transform

Zone A in Nanpu Sag of Bohai Bay has the characteristics of multiple provenances, multiple sedimentary systems, fast phase transition, many faults, a short fault distance, thin reservoirs and rapid lateral changes. At present, due to the low resolution of seismic data and thin sand layer of the target formation, it is difficult to depict the channel sand body, and it is also difficult to meet the requirements of accurately implementing low amplitude structures, reservoir prediction and well location deployment. When a seismic wave propagates in the stratum, it has the characteristics of multi-scale, multi-resolution and multi-directionality, while the Curvelet transform has the advantage of expressing these characteristics. In this paper, according to the geological characteristics and seismic response characteristics of continental thin interbedded strata in zone A, the seismic data are first transformed to the Curvelet domain. Then, the formation absorption and seismic wave attenuation are compensated in the Curvelet domain. Lastly, the data mentioned above are inversely transformed into the time–space domain. This paper presents the method and process of using the Curvelet transform to enhance the resolution of seismic data in thin interbedded strata. The application of a theoretical model and field data show that this method can effectively enhance the resolution of seismic data while maintaining a high signal-to-noise ratio. The innovative use of this method in zone A lays the foundation for the follow-up work of this structure.

An integrated organic–inorganic geochemical characterization of Paleogene sediments in No.1 Structural Belt of the Nanpu Sag, Bohai Bay Basin, eastern China: implications for the origin of organic matter

Paleogene sediments, especially the third member of the Dongying Formation (Ed 3 ) and the first and third members of the Shahejie Formation (Es 1 and Es 3 ), have been regarded as the most important source rocks in the Nanpu Sag. Organic and inorganic analyses, including Rock-Eval pyrolysis, gas chromatography-mass spectrometry, and element geochemistry, in 91 mudstone samples, were used to reconstruct the palaeoenvironmental conditions, such as palaeoclimate, palaeo-salinity and palaeo-redox conditions, and to recognize the origin of organic matter. The results show that Es 3 has a higher TOC content than Es 1 and Ed 3 . Hydrocarbon genetic potential (S 1 + S 2 ) of the samples indicate fair to good hydrocarbon potential. The kerogen type of Ed 3 and Es 1 source rocks are Type II 1 –II 2 , while Es 3 source rocks are dominated by Type II 2 –III kerogens. Biomarkers and inorganic geochemical indicatives of source rocks, such as Pr/Ph, V/(V + Ni) and Cu/Zn, indicate a lacustrine environment with fresh to brackish water under suboxic to anoxic conditions during deposition. Ed 3 source rocks are characterized by low G/C 30 H (gamacerane/C 30 hopane) (<0.1), TT/C 30 H (tricyclic terpane/C 30 hopane) and S/H (serane/hopane), high Pr/Ph (pristane/phytane) and C 24 TeT/C 23 TT (C 24 tetracyclic terpane/C 23 tricyclic terpane), indicating mixed input of both algae and terrestrial higher plants, dominated by terrestrial higher plants. Es 1 source rocks display medium G/C 30 H, TT/C 30 H, S/H, Pr/Ph and C 24 TeT/C 23 TT, indicative of a mixed input of both algae and terrestrial higher plants. Es 3 source rocks are characterized by high G/C 30 H (>0.1), TT/C 30 H and S/H, low Pr/Ph and C 24 TeT/C 23 TT, typical of a mixed input of algae and terrestrial higher plants, with algal dominance. Ed 3 , Es 1 and Es 3 source rocks were mostly deposited in semi-arid to humid-warm climate conditions, with an average temperature higher than 15°C. This study suggests that suitable temperatures, a fresh to brackish lacustrine environment and suboxic to anoxic conditions could result in a high organic matter concentration and preservation, thus providing prerequisites for the formation of high-quality source rocks. Supplementary material : Tables S1–S3 are available at https://doi.org/10.6084/m9.figshare.c.5227684

Hydrocarbon source potential evaluation insight into source rocks—A case study of the first member of the Paleogene Shahejie Formation, Nanpu Sag, NE China

The features of source rock hydrocarbon generation, expulsion, and retention are essential factors in petroleum resource potential evaluation. In this study, the improved hydrocarbon generation potential evaluation method was used to quantify the characteristics of the source rocks of the first member of the Paleogene Shahejie Formation (Es1) in the Nanpu Sag, Bohai Bay Basin, NE China. Based on the geological and geochemical data for the source rocks, the favorable exploration areas were predicted and the resource potential was evaluated. Our results show that Es1 is a set of high-quality source rocks with desirable geological (maximum thickness > 600 m) and geochemical (average total organic carbon content of 1.44%; dominantly type II kerogen; mature stage) characteristics. The improved hydrocarbon generation potential model shows that the hydrocarbon expulsion threshold is located at Ro=1.0%. The maximum hydrocarbon generation potential (Qg), hydrocarbon expulsion potential (Qe), hydrocarbon retention potential (Qs), and efficient hydrocarbon retention potential (Qse) are 549.31, 162.20, 387.11, and 287.11 mg HC/g TOC, respectively. The maximum hydrocarbon generation, expulsion, retention, and effective retention intensities are 250×104, 70×104, 180×104, and 150×104 t/km2, respectively. These parameters reach the highest value in the Linque and Caofeidian Sub-sag. The resource potential of the retention shale oil, the movable shale oil, and the conventional and the tight petroleum resources are 1.99×108, 4.38×108, and 1.37×108 t oil equivalent, respectively. This study offers a fresh and plain but operable workflow for resource evaluation, which can be applied in other petroliferous basins with low degree of exploration.

Qualitative and quantitative prediction of diagenetic facies via well logs

Drilled cores, thin section petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), routine core analysis (RCA), and mercury injection capillary pressure (MICP) tests were used to establish a predictable model for diagenetic facies and reservoir quality using well logs in sandstones of the Paleogene Dongying Formation in Nanpu Sag, Bohai Bay Basin, Eastern China. The results show that the sandstones are texturally and compositionally immature, and have primary intergranular pores, secondary intergranular and intragranular pores, moldic pores, and micro-pores associated with diagenetic clay minerals. The sandstones have undergone low to moderate mechanical compaction, but a high degree of framework-grain dissolution. Diagenetic minerals are dominantly of carbonates (calcite, dolomite, and Fe-dolomite) and clay minerals (illite, mixed layer illite/smectite and kaolinite). Four types of diagentic facies are recognized: tightly compacted, carbonate cemented, clay mineral filling, and dissolution facies. Porosity, permeability and oil saturation ranges among these diagenetic facies were determined from routine core analyses. The diagenetic facies were then translated to conventional well logs by core-log calibration, and the well log expressions (in terms of natural gamma ray, neutron porosity, bulk density, sonic transit time, and resistivity logs) of various diagenetic facies were summarized. The mineralogical composition obtained from the Elemental Capture Spectroscopy (ECS) logs was then used for the diagenetic facies prediction. The diagenetic facies predicted with the comprehensive conventional log analyses were combined with the ECS log profile, and were calibrated with the XRD, SEM analysis and logging interpretation results. For wells without ECS log, the diagenetic facies can be quantitatively predicted by the mathematical calculations of reservoir quality index (RQI) via the GR, AC and DEN log curves. Reservoir quality or oil bearing properties can be evaluated and predicted by translating the diagenetic facies to well logs.

Sedimentology of Shahejie Formation, Bohai Bay Basin: a case study of Es1 member in Nanpu Sag

The Es1 sandstone is a fruitful hydrocarbon zone of Eocene Shahejie Formation. Therefore, the present study comprises the subsurface facies analysis established on the description of seven wells. Methods include core observation, thin section petrography, scanning electron microscope (SEM), cathodoluminescence (CL), and X-ray diffraction to evaluate the microfacies, lithofacies, and rock characteristics. Two microfacies of lithofacies have been established as sandstone microfacies and mudstone microfacies on the basis of grain size. Among them, sandstone is further divided into four sub-microfacies on the basis of microscopic studies, rock fragments and mineral composition, which are arkose sandstone, lithic arkose, feldspathic litharenite, and litharenite. These microfacies consisting quartz, feldspar as abundant detrital grains followed by rock fragments and micas, whereas calcite, ferro-calcite, quartz overgrowth, and clay are the main cement. The Es1 sandstone consists of good primary porosity and permeability as well as good secondary porosity caused by fracturing and dissolution of unstable minerals that enhance the reservoir quality. Whereas cementation and compaction reduce the reservoir characteristics. Studied formation divided into five lithofacies including conglomerate sandstone lithofacies, medium to coarse-grain sandstone lithofacies, fine sandstone lithofacies, siltstone lithofacies, and mudstone lithofacies. Core observation, sedimentary structures, facies sequences of the well log, and sedimentary composition reveal that Es1 deposited into the lacustrine delta fan depositional environment. Rock grain size indicates that Es1 contains mixtures of grains including pebbles, sand-size as well as minor silt and clay size. Grain size varies from conglomerate to clay size. The Es1 sandstone was deposited in braided river (conglomerates sandstone), channel bar, lacustrine, fluvial channel (massive bedding, cross-bedding, and graded bedding sandstone), deltaic, and flood-plain (siltstone and mudstone) sedimentary environment. It is concluded that higher transport energies in channels deposited coarse-grain sediments in shallowest part of the lake setting. However, the energy decreases towards greater depth which deposited mudstone in central part of the lake.

Organic geochemistry, hydrocarbon generation, and expulsion characteristics and their impact on tight oil: A case study of the third member of the Upper Palaeogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, NE China

In recent years, exploration of tight oil in the Nanpu Sag has made significant progress in the third member of the Upper Palaeogene Shahejie Formation (Es3) in the Nanpu Sag, Bohai Bay Basin, Northeast China, showing excellent prospects. However, owing to insufficient understanding of the hydrocarbon generation and expulsion characteristics of Es3 source rocks and their matching relationship with the reservoir tightening time, the genetic type and resource potential of tight oil systems are not precise, which limits the further exploration of tight oil. In this study, the geological and geochemical characteristics of Es3 source rock are identified through a comprehensive geological and organic geochemistry analysis. In addition, hydrocarbon generation and expulsion patterns are established using a hydrocarbon generation potential model. On the basis of these results, combined with sandstone reservoir evolution histories, we have identified the genetic type and resource potential of the tight oil. The results show that the kerogen types of the Es3 source rocks of the Nanpu Sag, are widely distributed in an area of nearly 1,000 km2 and have a large thickness of more than 700 m, are mainly Types II and III with a high average total organic carbon (TOC) value of 1.63%. Moreover, the source rocks are primarily in the mature stage, with an average vitrinite reflectance (Ro) of 1.06%. The Es3 source rock reached the hydrocarbon expulsion threshold at Ro = 0.7%, and the hydrocarbon expulsion efficiency was approximately 70%. Two hydrocarbon generation and expulsion centres are identified, the Gaoshangpu and Laoyemiao structural belts, with maximum hydrocarbon generation and expulsion intensities of 100 × 106 t/km2 and 80 × 106 t/km2, respectively. In addition, two genetic types of tight oil are identified with accumulation before and after tightening, respectively. The resources of these types are 2.3 × 108 t and 20.4 × 108 t, respectively, with a total of 22.7 × 108 t, which indicates significant prospects for tight oil exploration.

Diagenetic evolution and formation mechanisms of middle to deep clastic reservoirs in the Nanpu sag, Bohai Bay Basin, East China

Abstract The reservoir properties, diagenetic features and evolution of the Paleogene Shahejie Formation (Es) in the Nanpu sag, Bohai Bay Basin were analyzed based on mineralogical and petrological data, and the main controlling factors and formation mechanisms of medium to deep high-quality reservoir were revealed by multiple regression analysis. The results show that the sedimentary microfacies, rigid grains content, and dissolution process are the key factors controlling the formation of high-quality clastic reservoir in middle to deep depth in the Nanpu sag. The formation mechanisms of middle to deep sandstones of the Es in different structural belts differ widely in formation mechanism. The Es1 (uppermost member of Es) sandstone reservoirs in the Nanpu No.3 structural belt is low porosity, moderate to high permeability reservoir in the mesodiagenesis A2 stage on the whole, and the formation of high-quality reservoirs is mainly attributed to strong compaction resistance ability primarily, and dissolution process secondarily. The Es3 (third member of Es) sandstones in Gaoshangpu structural belt is classified as tight sandstones in the mesodiagenesis A1 stage, in which the development of favorable reservoirs is primarily controlled by dissolution. This study provides references for reservoir evaluation of deep clastic reservoirs and exploration deployment in the Bohai Bay rift basin. As there are high-quality reservoirs, it is believed that the deep clastic reservoirs in the eastern of China, such as Bohai Bay Basin still have significant exploration potential.

Predicting 3D heterogeneous in situ stress field of Gaoshangpu Oilfield northern area, Nanpu Sag, Bohai Bay Basin, China

Research on in situ stress has important theoretical and practical significance for the exploration and development of oil and gas reservoirs. The orientation and magnitude of in situ stress in the Gaoshangpu Oilfield northern area (GO-NA) were analyzed using borehole breakout data and acoustic emission measurements. Mechanical experiments, logging interpretation, and seismic data enabled spatial characterization of rock mechanics parameters. A 3D geological model and 3D heterogeneous rock mechanics field of the GO-NA were constructed. Petrel and ANSYS modeling provided detailed prediction of the 3D stress field in the GO-NA. The results indicate that the maximum horizontal stress orientation in the GO-NA is generally ENE–WSW-trending, with significant changes in in situ stress orientation within and between fault blocks. Along surfaces and profiles, stress magnitudes are discrete and in situ stress is of the Ia-type. Observed inter-strata differences were characterized by five different types of in situ stress profile. Faults are the most important factor in the large distributional differences in the stress field of reservoirs observed within the complex fault blocks, significantly affecting magnitudes and orientations in the stress field. The next most important influence on the stress field is the reservoir’s rock mechanics parameters, which affect in situ stress magnitudes. A strong linear correlation exists between reservoir depth and in situ stress magnitude. This technique provides a theoretical basis for more efficient exploration and development of low-permeability reservoirs. It also serves as a reference for the detailed prediction of inter-well in situ stress in regions with similarly complex fault blocks.

Sedimentology, diagenetic evolution, and sweet spot prediction of tight sandstone reservoirs: A case study of the third member of the Upper Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, China

Substantial progress has been made in the exploration of the tight petroleum resources in Bohai Bay Basin, as a series of tight oil reservoirs were discovered. Among these reservoirs, a new breakthrough was achieved in the Nanpu Sag, proving a previously unconfirmed prospect of tight oil. Mineralogical, petrographic and fluid inclusions analyses were performed to investigate physical properties (composition, pore system, porosity, and permeability), controlling factors, and features of tight sandstones of the Upper Paleogene Es3 (the third member of the Shahejie Formation) in the Gaoshangpu Structural Belt of the Nanpu Sag. Our study indicates that the Es3 tight sandstones are mainly feldspathic litharenites and had low values for porosity (average value 10.1%) and permeability (average value 0.8 mD). The pore system is dominated by secondary dissolution pores (average thin porosity 3.1%). The deterioration of porosity is greater due to compaction (average compaction rate 68.8%) rather than cementation (average cementation rate 16.3%). Two peaks in the homogenization temperature were observed; the first ranges from 116 °C to 136 °C and exhibits yellow fluorescence, while the other peak varies from 156 °C to 165 °C, showing blue fluorescence, which indicates two stages of hydrocarbon charging at 26 Ma and 3 Ma, respectively. Tight sandstone is identified during the Mesodiagenesis phase. Eodiagenesis included compaction, precipitation of calcite cements and quartz overgrowth. Mesodiagenesis mainly exhibited compaction and grain dissolution (mainly feldspar). The main controlling factors can be summarized as follows, with the second factor being the most important: (a) a high energy deposition environment (distributary channels); (b) intense dissolution; and (c) early hydrocarbon charging and overpressure. This study provides a new prospect of the tight sandstone petroleum system in northeastern China.

An improved hydrocarbon generation potential method for quantifying hydrocarbon generation and expulsion characteristics with application example of Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin

Abstract To evaluate petroleum resources, it is important to quantify the hydrocarbon generation and expulsion characteristics of source rock. The hydrocarbon generation potential method is an efficient model for calculating the characteristics of source rocks and evaluating the resource potential. The previous hydrocarbon generation potential model was mainly established by measured Rock-Eval pyrolysis data, and due to inappropriate preservation measures, an important component (volatile hydrocarbon content) of source rock may be significantly reduced. Prior methods may, therefore, not objectively reflect the properties of a source rock and cause unacceptable errors in the resource assessment. This study proposes an improved hydrocarbon generation potential method. The new method considers the initial hydrogen index (HI0) and transformation ratio (Tr) during the evolution of source rocks, which can more realistically reflect the hydrocarbon generation and expulsion history of source rocks. Therefore, the hydrocarbon evaporative loss (Qloss) is calibrated and the hydrocarbon generation and expulsion features of source rocks are more accurately evaluated. The proposed method is used to examine the effectiveness of the third member of the Upper Paleogene Shahejie Formation (Es3) in Nanpu Sag. By utilizing the improved hydrocarbon generation potential model, the hydrocarbon expulsion threshold of the Es3 source rock is positioned at Ro = 0.875%. The maximum hydrocarbon generation and expulsion potential (Qg and Qe) are 593.78 and 323.78 mg HC/g TOC, respectively, and the maximum hydrocarbon expulsion efficiency is 54%. The maximum hydrocarbon generation and expulsion intensities are 500 × 104 t/km2 and 250 × 104 t/km2, respectively, which locate source rock at the Laoyemiao and Gaoshangpu Structural Belts. The amounts of generated and expelled hydrocarbon are 13.7 × 108 t and 6.9 × 108 t, respectively, and the resource potential of the tight oil of the Es3 in the Nanpu Sag is 0.69 × 104 t. Compared with the previous method, the improved hydrocarbon generation potential method limits the maximum Qg and calibrates the Qloss; therefore, the new method more objectively reflects the hydrocarbon generation and expulsion characteristics and resource prospect of the source rock.

In‐situ stress determination and fracture characterization using image logs: The Paleogene Dongying Formation in Nanpu Sag, Bohai Bay Basin, China

AbstractFracture detection and in‐situ stress determination via well logs are important for exploration and exploitation of subsurface hydrocarbons. Cores, thin sections, and image logs are used to describe and interpret the subsurface fractures and in‐situ stress in the Paleogene Dongying sandstones in Nanpu Sag, Bohai Bay Basin, China. The maximum horizontal stress (SHmax) indicates a nearly east‐west trend according to the borehole breakouts and drilling‐induced fractures. Natural fractures in the Dongying sandstones are classified into: (1) open fractures and (2) closed fractures. The cement‐filled (closed) fractures are commonly detected by image logs as bright discontinuous sinusoidal waves due to resistive filling materials, while the open fractures are evident on image logs appearing as dark sine waves. The open fractures are of dominantly high dip angles, and the rose diagrams confirm the presences of two sets of fractures: northwest‐southeast and northwest‐southeast orientation. Fractures with strikes approximately parallel to the SHmax have good connectedness, making a significant contribution in hydrocarbon production. In addition, the oil‐bearing layers are mainly associated with the intervals with open fractures. The presence of natural fractures provides important pore spaces and fluid flow conduits. Insights can be provided into the subsurface fracture (natural and induced) detection and characterization using image logs.