Search Results (10)

Paleoenvironmental insights gleaned from geological history are profoundly important for the discovery and exploitation of mineral resources. In China’s Bohai Bay Basin, the Kongdian Formation represents the principal oil-bearing stratum from the Eocene Epoch. However, a comprehensive understanding of its paleoenvironmental evolution and stratigraphic division has been hindered by the paucity of paleontological data. To address this gap, three sedimentary cores were meticulously collected from the southern extremity of the Liaoxi Uplift within the Bohai Bay. These cores underwent a thorough sporopollen-algae analysis to elucidate their stratigraphic division and to reconstruct the associated paleoenvironmental conditions. The analysis yielded the identification of three distinct sporopollen-algae assemblages of the regional Kongdian Formation: (1) The assemblage of Divisisporites longilaesuratus-Betulaepollenites-Tiliaepollenites microreticulatus is indicative of the lower submember of the Kongdian Formation Ek₂; (2) The assemblage of Polypodiaceaesporites-Alnipollenites indicates the upper submember of the Ek₂; (3) The assemblage of Pterisisporites undulatus-Taxodiaceaepollenites-Ephedripites corresponds to the Kongdian Formation Ek₁. These assemblages reflect a significant evolutionary trajectory of the regional plant communities throughout the Kongdian Formation. Initially, there were evergreen arbor-shrub mixed forests, which transitioned to green algae-herb-evergreen broadleaved biota and finally evolved into evergreen conifer-shrub mixed forests. This botanical evolution mirrors shifts in the paleoclimate, which experienced a progression from conditions of high temperature and high humidity through a phase of warm, semi-humid environments to eventually high temperature and semi-arid conditions. Full article

Shale oil resources are abundant in the second member of the Kongdian Formation, Cangdong Sag, Bohai Bay Basin, China. However, the shale oil here has high viscosity and poor fluidity, resulting in low recovery and huge difficulty in development, gathering, and transporting. This study assembled a catanionic surfactant (PSG) through electrostatic interactions between cetyltrimethylammonium bromide (CTAB) and α-olefin sulfonate (AOS) in an aqueous phase, which can be used as an effective emulsifying and viscosity-reducing agents for shale oils of Dagang oilfield. The interfacial activity and emulsification performance of PSG can be optimized by changing the molar ratio of CTAB to AOS. Notably, the PSG assembled at the molar ratio of 6:4 shows the best performance, with ultra-high surface activity and excellent salt resistance. At an oil/water ratio of 1:1 and 50 °C, an aqueous solution of 0.2% PSG can emulsify five types of shale oil, making it form shale oil-in-water (O/W) emulsion with a viscosity of less than 35 mPa·s, thereby reducing the viscosity of shale oil and improving its flowability. Importantly, shale oil and water can be separated by simple sedimentation without adding demulsifiers. This study has important guiding significance for the efficient development and transportation of shale oil. Full article

By using gas physisorption and multifractal theory, this study analyzes pore structure heterogeneity and influencing factors during thermal maturation of naturally immature but artificially matured shale from the Kongdian Formation after being subjected to hydrous pyrolysis from 250 °C to 425 °C. As thermal maturity increases, the transformation of organic matter, generation, retention, and expulsion of hydrocarbons, and formation of various pore types, lead to changes in pore structure heterogeneity. The entire process is divided into three stages: bitumen generation stage (250–300 °C), oil generation stage (325–375 °C), and oil cracking stage (400–425 °C). During the bitumen generation stage, retained hydrocarbons decrease total-pore and mesopore volumes. Fractal parameters ΔD indicative of pore connectivity shows little change, while Hurst exponent H values for pore structure heterogeneity drop significantly, indicating reduced pore connectivity due to bitumen clogging. During the peak oil generation stage, both ΔD and H values increase, indicating enhanced pore heterogeneity and connectivity due to the expulsion of retained hydrocarbons. In the oil cracking stage, ΔD increases significantly, and H value rises slowly, attributed to the generation of gaseous hydrocarbons further consuming retained hydrocarbons and organic matter, forming more small-diameter pores and increased pore heterogeneity. A strongly negative correlation between ΔD and retained hydrocarbon content, and a strongly positive correlation with gaseous hydrocarbon yield, highlight the dynamic interaction between hydrocarbon phases and pore structure evolution. This study overall provides valuable insights for petroleum generation, storage, and production. 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

In contrast to marine shale oil reservoirs, lacustrine shale exhibits rapid lithofacies changes and strong mineral compositional heterogeneity, posing new challenges for the evaluation and distribution prediction of shale oil sweet spots. The oiliness, reservoir properties, oil fluidity, and fracability of different lithofacies were analyzed using emission-scanning electron microscopy (FE-SEM) observation, low-pressure nitrogen physisorption (LNP) analysis, mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), and triaxial compression testing. Based on the mineral composition obtained from X-ray diffraction (XRD) analysis, total organic carbon (TOC) content, and sedimentary structure, four lithofacies were classified, which are organic-rich laminated calcareous shale (LC), organic-rich laminated siliceous shale (LS), organic-rich laminated mixed shale (LM), and organic-poor massive calcareous shale (MC). Considering the factors of oiliness, reservoir properties, oil fluidity, and fracability, the LC and LS lithofacies were determined as being high-quality sweet spots (type I). Within the stratigraphic sequence divided by GR-INPEFA curves, multi-resolution graph-based clustering (MRGC) analysis of sensitive well logs was used to classify the lithofacies, after which the distribution of sweet spots was predicted. The results reveal that the sweet spots exhibit regular changes in their vertical distribution and a ring-like pattern in their planar distribution, influenced by variations in the sedimentary environment. This finding can offer valuable guidance for the future exploitation of shale oil in the Guandong region. Full article

The lacustrine shale in the second member of the Kongdian Formation (Ek2) is the most significant target of shale oil exploration in the Cangdong Sag, Bohai Bay Basin, China. To investigate the occurrence mechanisms and to reveal the influencing factors of shale oil mobility in Ek2, a series of analyses (X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), total organic carbon (TOC) analysis, Rock-Eval pyrolysis, low-temperature nitrogen physisorption (LNP), mercury intrusion porosimetry (MIP), and multiple isothermal stage (MIS) pyrolysis) were conducted on samples collected from well cores in the Cangdong Sag. The results show that the lithofacies can be categorized as laminated felsic shales, laminated and massive mixed shales, and laminated and massive carbonate shales. The shales were characterized by a high organic matter abundance and moderate thermal evolution with good to excellent hydrocarbon generation potential and contained a high abundance of Type I and II1 kerogens. Laminated felsic shales and laminated mixed shales, compared with other lithofacies, had clear advantages in the amount of free hydrocarbon that can be volatilized from the rock (S1), the oil saturation index (OSI) value, and the free oil and movable oil content. LNP, MIP, and MIS pyrolysis analyses show that the residual shale oil mainly occurred in pores with diameters smaller than 200 nm, and the pore diameter when residual oil occurred in some laminated shale samples could reach 50 μm. The lower limits of the pore diameter where free oil and movable oil occurred were 7 and 30 nm, respectively. The mobility of shale oil is controlled by the shale oil component, thermal maturity, TOC content, and pore volume. The results herein provide a basis for the evaluation of optimal shale oil intervals. Full article

The Paleocene Kongdian Formation coarse clastic rock reservoir in Bozhong Sag is rich in oil and gas resources and has huge exploration potential. However, the coarse clastic rock reservoir has the characteristics of a complex pore structure and strong heterogeneity, which restrict the accuracy of evaluating the reservoir’s physical properties, such as porosity and permeability, for field evaluation. Nuclear magnetic resonance (NMR) technology has become a popular methods for unconventional reservoir evaluation because it can obtain abundant reservoir physical property information and because of its ability to identify fluid characteristics information. The transverse relaxation time (T₂) cutoff (T_2C) value is an important input parameter in the application of NMR technology. The accuracy of the T_2C value affects the accuracy of the reservoir evaluation. The standard method for determining the T_2C value requires a series of complicated centrifugation experiments in addition to the NMR experiments, and its application scope is limited by obtaining enough core samples. In this study, 14 core samples from the coarse clastic rock reservoir in the southwestern Bozhong sag of the Bohai Bay Basin were selected, and NMR measurements were carried out under the conditions of fully saturated water and irreducible water to determine the T_2C value. Based on the multifractal theory, the NMR T₂ spectrum of the saturated sample was analyzed, and the results show that the NMR T₂ distribution of the saturated sample has multifractal characteristics, and the multifractal parameter D_q and the singular intensity range Δα have a strong correlation with the T_2C value. Thus, based on multiple regression analyses of the multifractal parameters with the experimental T_2C value of 10 core samples, we propose a method to predict the T_2C value. After applying this method to 4 samples that were not used in the modeling, we confirmed that this method can be used to predict the T_2C value of core samples. Furthermore, we expanded this method to the field application of a production well in Bozhong sag by adding an empirical index in the model. The new model can be used to directly calculate the T_2C value of NMR logging data, and it does not require any other extra data, such as those from core analysis. This method is applicable in fast reservoir evaluations by only using NMR logging data in the field. The research results improve the accuracy of field NMR logging reservoir evaluations. Full article

The discovery of the BZ19-6 large-scale condensate gas field illustrates the great potential of the sandy conglomerate reservoirs in the Bohai Bay Basin. However, the stratigraphic correlation of the sandy conglomerate sequence in northern Huanghekou Sag remains a challenge due to the lack of syn-depositional volcanic layers and biostratigraphic constraints. The challenge limits understanding the regional strata distribution and further exploration deployment. In this study, we conducted in situ U-Pb dating of vein calcite and detrital zircons of the sandy conglomerate samples from borehole BZ26-A. The vein calcite age and the youngest age of detrital zircons provide the upper and lower bounds of the depositional age, respectively. We also correlated the samples with those from well-understood strata through a comparison of XRD mineral components. The absolute age of 47.0 Ma of the vein calcite and the youngest detrital zircon age of 103.5 Ma suggest the sedimentary sequence is supposed to be referred to as the Kongdian Formation (65–50.5 Ma). The XRD data and petrological analysis suggest that the lithostratigraphy of the Kongdian Formation in Huanghekou Sag could be divided into at least three members, with Member 3 consisting of red sediment deposited in a hot and dry climate; Member 2 and Member 1 deposited as fan delta with major parent rock of Mesozoic volcanic rocks and Precambrian meta-granitoid, respectively. Member 1 shows significant potential for energy exploration due to high brittle mineral components and fracture development. Full article

The characteristics of laminae are critical to lacustrine shale strata. They are the keys to the quality of source rocks and reservoirs, as well as engineering operations in shale plays. This study uses organic geochemistry, thin section identification, X-ray diffraction, field emission scanning electron microscopy, and other analytical methods, to reveal the detailed lamination texture and vertical distribution of laminae in the second Member of the Kongdian Formation in Cangdong Sag. The principal results are as follows: (1) A classification of laminae is proposed to characterize reservoir and geochemical properties. The five types of laminae are as follows: feldspar-quartz laminae (FQL), clay laminae (CLL), carbonate laminae (CAL), organic matter laminae (OML), and bioclastic laminae (BCL). There are also four significant lamina combinations (with the increasing TOC values): FQL-CLL combination, FQL-CLL-BCL combination, FQL-CLL-OML combination, and FQL-CAL-CLL-OML combination; (2) differences between laminae occur because of the variability in pore types and structures. There appears to be a greater abundance of intercrystalline pores of clay minerals in the FQL, CAL, BCL, and OML, and well-developed organic pores in the CAL and CLL, and the counterparts of intragranular pores of bioclastic material in the BCL. This detailed characterization provides the following comparative quantification of the thin section porosity of laminae in the second Member of the Kongdian Formation can be differentiated: CAL > FQL > OML > BCL > CLL; (3) differentiation between vertical distributions of laminae is carried out in a single well. The FQL and CLL are widely distributed in all the samples, while the BCL is concentrated in the upper part of the second Member of the Kongdian Formation, and CAL is concentrated in the lower part. This detailed classification method, using geochemical analysis and vertical distribution descriptions, offers a detailed understanding of lamination texture and its effects on reservoir and geochemical properties, which will provide a scientific guidance and technical support to better estimate reservoir quality and to identify new sweet spots in the second Member of the Kongdian Formation in the Cangdong Sag. Full article

The pore structure of rocks can affect fluid migration and the remaining hydrocarbon distribution. To understand the impacts of the base-level cycle on the pore structure of mouth bar sand bodies in a continental rift lacustrine basin, the pore structure of the mouth bar sand bodies in the ZVC (ZV4 + ZV5) of the Guan195 area was studied using pressure-controlled mercury injection (PMI), casting sheet image and scanning electron microscopy (SEM). The results show that three types of pores exist in ZVC, including intergranular pores, dissolution pores, and micro fractures. The porosity is generally between 1.57% and 44.6%, with a mean value of 19.05%. The permeability is between 0.06 μm² and 3611 μm², with a mean value of 137.56 μm². The pore structure heterogeneity of a single mouth bar sand body in the early stage of the falling period of short-term base-level is stronger than that in the late stage. During the falling process of the middle-term base level, the pore structure heterogeneity of a late single mouth bar sand body is weaker than that of an early single mouth bar sand body. In the long-term base-level cycle, the pore structure heterogeneity of mouth bar sand bodies becomes weaker with the falling of the base-level. Full article