Shale Oil Exploration Research Articles

Effects of Astronomical Cycles on Laminated Shales of the Paleogene Shahejie Formation in the Dongying Sag, Bohai Bay Basin, China

Laminated shales are widely developed in the Dongying Sag and have attracted much attention as an oil reservoir. Macroscopically, these shales generally have multi-scale cyclicity, which is closely related to the development of laminae. Therefore, analyzing the origin of their cyclicity is helpful to understanding the formation mechanism of laminated shales and the vertical heterogeneity of shale reservoirs, which are of great significance for continental shale oil exploration and development. In this study, a gamma ray (GR) logging series, high-resolution elemental geochemical data, high-resolution core scanning photos and grayscale data, and mineralogical data were used to characterize the cyclicity of shale at different scales, and their relationship with different astronomical cycles was discussed. The results show that the Es3L and Es4U shale in the Dongying Sag has cyclicity from the meter-scale to the ten-meter scale and then to the hundred-meter scale, which is mainly manifested by periodic changes in organic matter abundance, mineral composition, element abundance, and grayscale. These cycles of different scales coincide with different astronomical periods. Specifically, the hundred-meter scale cyclicity is mainly controlled by the very long orbital period; the ten-meter scale cyclicity is mainly related to the eccentricity cycle; while the precession period is the main driver of the meter-scale cyclicity. Finally, we propose a simplified model for illustrating the formation of rhythmic organic-rich shale. This study is helpful to understanding the origin of continental organic-rich shale and predicting shale reservoir properties.

Prediction of lamina structure and reservoir quality in shale using well logs: The Cretaceous Qingshankou Formation, Gulong Sag, Songliao Basin, China

Lamina structure is determined by composition, thickness, continuity, and mineral assemblage. Reservoir quality in oil shale reservoirs is determined by lamina structure, which controls hydrocarbon accumulation and migration. The prediction and evaluation of multi-scale lamina structures using geophysical well logs is challenging. Recent studies demonstrate that the lamina structure classification may be based on core observation and core analysis. However, there are no corresponding high-resolution geophysical logging methods to identify and categorize lamina structure continuously in a single well. Here, an experimental approach, involving an integrated analysis of cores, thin sections, well logs such as slabs and button conductivity curves of image logs (up to 5 mm vertical resolution), is used to characterize lamina structure. T1-T2 (T1, longitudinal relaxation time, and T2, transverse relaxation time) maps of nuclear magnetic resonance (NMR) logs are applied to clarify the relationships between the lamina structure, reservoir quality, and oil-bearing properties. Results demonstrate how lamina structure in shale can be divided into three types: laminated rocks, layered rocks, and massive rocks, according to observation of core at the lamina scale. The thickness of individual lamina is less than 0.01 m in the laminated rocks, and the layered rocks have bundles of genetically related laminae thickness ranging between 0.01 m and 0.1 m. In massive rocks there is no visible layering. The well log response patterns of the three types of lamina structure are established so that the distribution of lamina structure can be predicted in a single well via well logs. Results show that the oil-bearing shale intervals are dominated by laminated rocks and layered rocks, accounting for 90% of the studied Qingshankou Formation. In addition, the layered rocks play an important role in improving reservoir quality and the laminated rocks present moderate reservoir quality. The massive rocks show poor reservoir quality. Moreover, an increased proportion of felsic mineral content favors increased oil potential in oil shale reservoirs. The method is generally applicable and is of value in developing predictive indicators of subsurface reservoir sweet spots in shale oil and gas exploration and development.

Forecast of lacustrine shale lithofacies types in continental rift basins based on machine learning: A case study from Dongying Sag, Jiyang Depression, Bohai Bay Basin, China

Lacustrine shale in continental rift basins is complex and features a variety of mineralogical compositions and microstructures. The lithofacies type of shale, mainly determined by mineralogical composition and microstructure, is the most critical factor controlling the quality of shale oil reservoirs. Conventional geophysical methods cannot accurately forecast lacustrine shale lithofacies types, thus restricting the progress of shale oil exploration and development. Considering the lacustrine shale in the upper Es4 member of the Dongying Sag in the Jiyang Depression, Bohai Bay Basin, China, as the research object, the lithofacies type was forecast based on two machine learning methods: support vector machine (SVM) and extreme gradient boosting (XGBoost). To improve the forecast accuracy, we applied the following approaches: first, using core and thin section analyses of consecutively cored wells, the lithofacies were finely reclassified into 22 types according to mineralogical composition and microstructure, and the vertical change of lithofacies types was obtained. Second, in addition to commonly used well logging data, paleoenvironment parameter data (Rb/Sr ratio, paleoclimate parameter; Sr %, paleosalinity parameter; Ti %, paleoprovenance parameter; Fe/Mn ratio, paleo-water depth parameter; P/Ti ratio, paleoproductivity parameter) were applied to the forecast. Third, two sample extraction modes, namely, curve shape-to-points and point-to-point, were used in the machine learning process. Finally, the lithofacies type forecast was carried out under six different conditions. In the condition of selecting the curved shape-to-point sample extraction mode and inputting both well logging and paleoenvironment parameter data, the SVM method achieved the highest average forecast accuracy for all lithofacies types, reaching 68%, as well as the highest average forecast accuracy for favorable lithofacies types at 98%. The forecast accuracy for all lithofacies types improved by 7%–28% by using both well logging and paleoenvironment parameter data rather than using one or the other, and was 7%–8% higher by using the curve shape-to-point sample extraction mode compared to the point-to-point sample extraction mode. In addition, the learning sample quantity and data value overlap of different lithofacies types affected the forecast accuracy. The results of our study confirm that machine learning is an effective solution to forecast lacustrine shale lithofacies. When adopting machine learning methods, increasing the learning sample quantity (>45 groups), selecting the curve shape-to-point sample extraction mode, and using both well logging and paleoenvironment parameter data are effective ways to improve the forecast accuracy of lacustrine shale lithofacies types. The method and results of this study provide guidance to accurately forecast the lacustrine shale lithofacies types in new shale oil wells and will promote the harvest of lacustrine shale oil globally.

Characteristics and Model of Heterogeneous Wettability in a Marine-Continental Transitional Shale Reservoir: Insights from Organic Matter, Minerals, and Microstructure

Heterogeneous wettability is characterized by a spotted-wet or mixed-wet state. It has a great influence on reservoir evaluation and the efficient development of shale gas reservoirs. In this study, reservoir properties of several core plugs from the Permian Shanxi–Taiyuan formations were studied. These formations are typical marine-continental transitional shale located in the Southern North China Basin. To investigate the effects of reservoir properties on heterogeneous wettability, we measured the water–air contact angle and compared it with other properties such as organic petrology, organic geochemistry, mineralogy, and microstructure features, including pore-fractures and surface roughness. The results reveal a negative correlation of vitrinite content with contact angle, in addition to the high clay content and residual polar groups within type III kerogen, indicating that the Shanxi–Taiyuan shales with a high maturity level still have a higher affinity to water. The contact angle of the core samples decreases with increasing surface roughness, partially due to the influence of pore-fracture development. The crossplots indicate that the majority of pore-fractures that exist in the shale preferentially tend to be water-wet. Therefore, the heterogeneous wettability of shale is dominated by the random mixture and arrangement of hydrophilic and hydrophobic components as well as the complexity of the microstructure, such as the rough pore wall. Furthermore, on the basis of improving and examining the Cassie model, a triangle method and a detailed workflow for evaluating the heterogeneous wettability of shale are proposed by comprehensively analyzing “three factors”, including pore structure, mineral components, and organic matter. The test results demonstrate that the Shanxi–Taiyuan shales are mainly water-wet (controlled by organic factor) and neutral-wet, which evidently differ from the marine Longmaxi shale with a wide distribution covering the zones of strongly water-wet, weakly water-wet (controlled by pore factor), and weakly water-wet (neutral-wet). The proposed approach can be applied to promptly and comprehensively evaluate and predict the heterogeneous wettability of shales during shale oil and gas exploration.

Classification and well-log identification of lithofacies of continental shale oil reservoirs in Chang 7-3 submember of the Triassic Yanchang Formation in the Longdong area of the Ordos Basin, China

The division and identification of lithology and lithofacies are very important in exploration and development of oil and gas reservoirs. Information on lithofacies determines the development modes and provides the favorable “sweet spot” intervals of shales. The Chang 7-3 submember of the Triassic Yanchang Formation in the Longdong area of the Ordos Basin is an important shale formation in China. Core photos, cast thin sections, and log response characteristics were used to clarify the development and distribution characteristics of the various lithofacies in this formation. The lithofacies of target intervals are classified into fine-grained sandy debrite, silty to fine-grained sandy turbidite, fine-grained sandy slump, semideep to deep lacustrine mudstone, and deep lacustrine shale. Furthermore, the conventional and microresistivity imaging log response characteristics of different lithofacies are analyzed. Compared with other lithofacies, deep lacustrine shale facies are characterized by high gamma ray (GR), high compensated neutron log (CNL), high acoustic log (AC), and low-density (DEN) log values. Crossplots of GR-AC, DEN-CNL, and DEN-AC are proposed to identify most of the lithofacies, and a criterion was established for use of well logs to characterize the lithofacies. Finally, a method joining conventional logs and microresistivity imaging log data was applied to field wells, achieving the very high accuracy rate of 88%. The distribution maps of different lithofacies thickness in the study area are obtained. Deep lacustrine shale facies have the widest development area and many thickness centers. Accurate and effective identification of lithofacies indicates that within the Ordos Basin, there is an area of approximately 20,000 km2 with shale thickness of greater than 6 m, providing an important basis for shale oil exploration in the study area.

Depositional Environment and Lithofacies Analyses of Eocene Lacustrine Shale in the Bohai Bay Basin: Insights from Mineralogy and Elemental Geochemistry

AbstractThe effect of various depositional parameters including paleoclimate, paleosalinity and provenance, on the depositional mechanism of lacustrine shale is very important in reconstructing the depositional environment. The classification of shale lithofacies and the interpretation of shale depositional environment are key features used in shale oil and gas exploration and development activity. The lower 3rd member of the Eocene Shahejie Formation (Es3x shale) was selected for this study, as one of the main prospective intervals for shale oil exploration and development in the intracratonic Bohai Bay Basin. Mineralogically, it is composed of quartz (avg. 9.6%), calcite (avg. 58.5%), dolomite (avg. 7%), pyrite (avg. 3.3%) and clay minerals (avg. 20%). An advanced methodology (thin‐section petrography, total organic carbon and total organic sulfur contents analysis, X‐ray diffraction (XRD), X‐ray fluorescence (XRF), field‐emission scanning electron microscopy (FE‐SEM)) was adopted to establish shale lithofacies and to interpret the depositional environment in the lacustrine basin. Six different types of lithofacies were recognized, based on mineral composition, total organic carbon (TOC) content and sedimentary structures. Various inorganic geochemical proxies (Rb/Sr, Ca/(Ca + Fe), Ti/Al, Al/Ca, Al/Ti, Zr/Rb) have been used to interpret and screen variations in depositional environmental parameters during the deposition of the Es3x shale. The experimental results indicate that the environment during the deposition of the Es3x shale was warm and humid with heightened salinities, moderate to limited detrital input, higher paleohydrodynamic settings and strong oxygen deficient (reducing) conditions. A comprehensive depositional model of the lacustrine shale was developed. The interpretations deduced from this research work are expected to not only expand the knowledge of shale lithofacies classification for lacustrine fine‐grained rocks, but can also offer a theoretical foundation for lacustrine shale oil exploration and development.

Effect of petroleum chemical fraction and residual oil content in saline lacustrine organic-rich shale: A case study from the Paleogene Dongpu Depression of North China

Halite and gypsum minerals in saline shale makes the retention mechanism and chemical fractionation of residual oil unique. The Dongpu Depression in North China is a typically saline lacustrine basin with developing halite and gypsum. The effect of gypsum minerals on residual oil content and chemical fractionation remains unclear. In this study, shale samples with different gypsum contents were used in organic geochemical experiments, showing that the high total organic matter (TOC) content and type Ⅱ kerogen leads to a high residual oil content, as shown by high values of volatile hydrocarbon (S1) and extractable organic matter (EOM). XRD and FE-SEM result indicate that the existence of gypsum in saline shale contributes to an enhanced pore space and a higher residual oil content in comparison to non-gypsum shale. Additionally, the increase in the gypsum mineral content leads to an increase in the saturated hydrocarbon percentage and a decrease in polar components percentage (resins and asphaltene). Furthermore, thermal simulation experiments on low-mature saline shale show that the percentage of saturated hydrocarbons in the residual oil is high and remains stable and that the storage space is mainly mesoporous (>20 nm) in the oil expulsion stage. However, the saturated hydrocarbons percentage decreases rapidly, and oil exists in mesopores (>20 nm and <5 nm) in the gas expulsion stage. In general, gypsum is conducive to the development of pore space, the adsorption of hydrocarbons and the occurrence of saturated hydrocarbon, leading to large quantities of residual oil. The data in this paper should prove to be reliable for shale oil exploration in saline lacustrine basins.

Pore Fractal Characteristics of Lacustrine Shale of Upper Cretaceous Nenjiang Formation from the Songliao Basin, NE China

The evaluation of pore characteristics in lacustrine shales is of significance for shale oil and gas exploration in terrestrial sedimentary basins. However, due to the complex depositional environments, there have been few reports on the quantitative evaluation of lacustrine pores. In this study, we carry out experiments, e.g., scanning electron microscopy (SEM), nitrogen adsorption, X-ray diffraction (XRD), and rock pyrolysis, on sixteen lacustrine shale core samples of the Late Cretaceous Nenjiang Formation (K2n1+2) in the Songliao Basin. At the same time, we bring in the fractal dimensions to quantitatively characterize the pores of shale samples in K2n1+2. The kerogen type of shales in the Nenjiang Formation is mainly type Ⅰ. The shales of K2n1+2 develop a large number of mineral intergranular pores and a small number of organic pores and mineral intragranular pores. The primary minerals of the samples are clay minerals and quartz. The total organic carbon (TOC) has a correlation with the pore physical parameters, whereas the content of minerals does not correlate significantly with pore development. The average pore fractal dimensions obtained from the analysis of nitrogen adsorption data are D1 = 2.5308 and D2 = 2.6557. There is a significant negative correlation between the fractal dimensions (D1 and D2) and the TOC content: the lower the fractal dimensions, the higher the TOC, and the more the free oil. In low maturity shales with higher TOC content, due to hydrocarbon generation, larger pores with a regular shape (small fractal parameters) can be produced, which can store more free oil. The shale reservoir evaluation of K2n1+2 in the Songliao Basin should be focused on shales with higher TOC and lower pore fractal parameters. Our work provides a reference for the shale oil evaluation of K2n1+2 in the Songliao Basin and complements studies on lacustrine pore characteristics.

Application of nanoindentation technique in mechanical characterization of organic matter in shale: Attentive issues, test protocol, and technological prospect

The rise of global shale oil and gas exploration has prompted scholars to pay attention to the mechanics of organic matter (OM) in shale reservoirs. The depth-sensing nanoindentation, a rather mature micromechanical testing technique in materials science, was gradually introduced into the mechanical data acquisition of shale matrix OM in recent years. Although this introduction is commendable, there are still some attentive issues relating to the indentation condition (mainly the reasonable setting of indentation depth parameter) and interpretation of the measured mechanical data, considering the micron-sized and nanoporous nature of OM and its close contact with surrounding minerals in shale composite. This study carried out a series of OM-positioned indentations on a typical shale sample collected from Silurian Longmaxi Formation in South China, in which we specially used the dynamic mechanical analysis that determines the mechanical data as a continuous function of indentation depth. Through it, we evidenced two main indentation effects (i.e., the size and substrate) during indentation of OM, and quantified the depths they appear (at less than 200 nm and greater than 1/20 of OM thickness, respectively). They together limit the indentation depth to a narrow range and also restrict the use of nanoindentation for OM less than 2 μm. Additionally, the porous OM is measured to be in lower mechanical values, suggesting that the porous effect on the indentation response cannot be ignored, especially when making mechanical comparison between different OM particles. Furthermore, we compared nanoindentation with the newly developed AFM-based nanomechanical mapping technique, and proposed to combine the both to achieve a full-scale characterization of shale matrix OM. Overall, this study standardized the indentation conditions to measure the inherent mechanical data of shale matrix OM, which lays the foundation for the forseeable increasing demand for testing and research of OM mechanics in the future.

Mineralogical and geochemical characterization of lacustrine calcareous shale in Dongying Depression, Bohai Bay Basin: Implications for paleosalinity, paleoclimate, and paleoredox conditions

Shale is an important self-sourced reservoir rock in many sedimentary basins worldwide. In this research work, a geochemical history of variations in the sedimentary environment of the lacustrine basin is analyzed based on extensive shale samples collected from the lower 3rd member (Es3L) and upper 4th member (Es4U) of the Paleogene Shahejie Formation in the Boxing Sag (Dongying Depression, East Coast of China). The representative shale samples were analyzed for total organic carbon (TOC) contents, mineralogical composition, the concentration of different elements (major, minor, and trace), kerogen types and vitrinite reflectance (Ro), and different sedimentary structures to understand the evolution of the depositional settings and their effect on the distribution of shale lithofacies in this basin. The TOC content in this shale ranges from 0.08 % to 13.6 %. Ro values range from 0.55 to 1.19 % with type-I to type-II kerogens. The studied shale is composed of calcite (average 37.83 wt%), dolomite (avg. 10.47 wt%), quartz (avg. 23.8 wt%), plagioclase (avg. 3.91 wt%), clay (avg. 20.84 wt%), and pyrite (avg. 2.85 wt%). Seven lithofacies have been established including mixed shale, calcareous shale, laminated limestone, argillaceous shale, dolomitic shale, siliceous shale, and siliceous dolomite based on mineral composition, TOC contents, and sedimentary structures. Different geochemical proxies including Sr/Ba, Ca/Ca + Fe, C-values, CIA values, Ti/Al, Al/Al + Fe, Al/Ti, V/V + Ni, Ni/Co, and Fe/Ca + Mg were used to interpret salinity, paleoclimate, detrital influx, provenance, paleoredox and water depth of the depositional environment in the studied shale. The detailed interpretation of the sedimentary environment suggested that during the deposition of Es3L shale, the terrigenous influx was high in shallow to a deep open lacustrine system with higher primary biogenic productivity. Semi-humid climatic conditions with higher precipitation rates prevailed during the deposition of this shale. On the other hand, relatively limited terrigenous input with low bioproductivity prevailed during the deposition of Es4U shale in the study area. Semiarid to humid climatic conditions with strong evaporation prevailed during the deposition of this shale. In this research work, a detailed depositional model of the Es3L–Es4U shale in Boxing Sag is established. The interpretations deduced from the current research work are likely to expand the knowledge of shale lithofacies and the genesis of lacustrine fine-grained sedimentary rocks, as well as can offer a theoretical foundation for lacustrine shale oil exploration and development.

Development model and identification of evaluation technology for Wufeng Formation–Longmaxi Formation quality shale gas reservoirs in the Sichuan Basin

In 2012, China's first national shale gas demonstrations areas were set up in the Sichuan Basin. After 10 years' construction and practice, the giant marine shale gas area of 10 × 1012 m3 level is built up in the Sichuan Basin, and shale gas steps into a new stage of large-scale benefit exploration and development. In order to systematically summarize the achievements in shale gas exploration and development and provide guidance and reference for the exploration and development of deep shale gas and shale oil & gas in other areas, this paper systematically summarizes the main characteristics, development models and key identification and evaluation technologies for quality reservoirs of Wufeng Formation–Longmaxi Formation shale gas by analyzing the electric property, lithofacies, reservoir parameters and microscopic porosity of key wells in the basin. And the following research results are obtained. First, biogenetic siliceous shale, calcareous shale and mixed shale are main lithofacies types in quality shale gas reservoirs, and they are formed in the environment of semi-deep and deep water continental shelf. Their lateral distribution is controlled by the paleogeomorphology and their vertical development is influenced by provenance, redox condition and paleo productivity. They are 25–90 m thick. Second, in the quality shale gas reservoirs develop organic pores, inorganic pore and microfractures (including lamina/bedding fractures), among which, organic pore is one of the main reservoir spaces and microfracture is not only indispensable reservoir space, but also production pathway. The reservoir space of shale gas is overall micro-nano pore, and macropores play an important role in shale gas enrichment. Third, three development models of quality reservoir are established, including sedimentary type, diagenesis type and reworking type. The sedimentary type is the foundation. Multiple quality reservoirs are developed in the high U/Th interval of graptolite belt at the bottom of Longmaxi Formation, and their thickness is mainly controlled by paleogeomorphology and especially greater in the depression area. The diagenesis type is divided into three forms, i.e., syngenetic-early diagenetic rigid support, middle-late diagenetic mineral-organic matter transformation, and overpressure relief compaction. The reworking type is dominated by quality reservoirs with microfractures. Fourth, the core technologies for identifying and evaluating quality shale gas reservoir include large-size core and rock slice observation, high-accuracy rock mineral identification, experimental gas content test and simulation, SEM microscopic characterization, 3D microscopic pore reconstruction, comprehensive geophysical interpretation and prediction and big data analysis. In conclusion, nearly 10 years' research and practice achievements in demonstration area construction can deepen the understanding on domestic quality shale gas reservoirs, promote the effective development of the theories and technologies related to shale gas reservoirs, improve the prediction accuracy of shale gas sweet spot zones/intervals, and expand the shale gas exploration and development achievements of demonstration areas.

Oil generation and expulsion modeling of the syn-rift Salif oil-source rock in the Tihamah Basin, Yemeni Red Sea: Implications for shale oil exploration

The Miocene Salif Formation is an oil-source rock within the Tihamah Basin, southern Red Sea of Yemen. The Salif shale beds are characterized by high organic carbon content (TOC) up to 5.59% and high oil saturation index (OSI) (30 < OSI <260 mg HC/g TOC). However, most of the Salif shale samples exhibit OSI values of >100 mg HC/g TOC, indicating a thermally mature and oil-saturated source rock system with high oil-bearing potential. This finding is supported by the vitrinite reflectance values, representing mature oil generation window. Therefore, the shale oil potential of the Salif source rock system is studied for the first time by integrating geochemical data and geological information into a 1-D modelling scheme. The models reconstructed for the thermal and burial history infers that the Salif source rock system is located within the late oil-window from the Late Pliocene to present-day. Kerogen to oil conversion and the timing of petroleum generation and expulsion are also simulated by the 1-D models, showing that 10–50% of the total kerogen is converted into oil during the early Pliocene to the Pleistocene, which is consistent with the peak-late mature oil-window (0.70–1.26 %Ro). The models also exhibited that limited oil was expelled from the Salif source rock system since the Pleistocene-present-day as demonstrated by the TR ratio of up to 55%. The integration of source rock evaluation and modeling approach concludes that the Salif source rock provides a good potential for possible oil production, where suitable reservoir characteristics do occur.

Geneses of multi-stage carbonate minerals and their control on reservoir physical properties of dolomitic shales

The formation and distribution of carbonate minerals have important influences on reservoir development. The dissolution-precipitation effect plays an important role in controlling the reformation of reservoir physical properties. High-quality source rocks with abundant reserves exist in the Lower Permian Fengcheng Formation, Junggar Basin, China, and the basin reservoir contains a large amount of carbonate minerals. Multi-stage cementation and dissolution of these carbonate minerals have important influences on diagenesis-porosity evolution of the reservoirs. Because of the coupled influences of deep fluid transformation and volcanic activity in the diagenetic evolution of the Fengcheng Formation, it has experienced a complex evolution of carbonate minerals. In this study, through core observation, thin section, X-ray diffraction mineral composition, carbon and oxygen isotope, fluid inclusion homogenization temperature, and laser Raman and cathodoluminescence analysis, the material sources, development period, dissolution-precipitation reactions, and transformation mechanisms of carbonate minerals in the diagenetic evolution of the Fengcheng Formation reservoir were evaluated in detail. Finally, the controlling effect of multi-stage cementation of carbonate minerals on the reservoir physical properties was determined. The results showed that there are three stages of carbonate minerals in the Fengcheng Formation. The material source of the early carbonate was mainly terrigenous debris, and the formation temperature range was 30–70 °C. The material source of middle-late carbonate minerals was mainly decarboxylation of organic acid, and the formation temperature was 60–110 °C. In addition, some were generated through hydrothermal metasomatism at high ambient temperatures, up to 120 °C. In areas where early carbonate minerals are well developed, a large number of microcracks was more likely to form under the influence of tectonic movements, resulting in high-quality reservoirs. The formation of late carbonate minerals, which is the main reason for reservoir densification in the later stage of diagenesis, resulted in poor reservoir physical properties. This study provides information useful for predicting the distribution areas of favorable reservoirs in the Fengcheng Formation, and a theoretical basis and guidance for improving the accuracy of shale oil exploration and development.

A Data-Driven Approach to the Unified Evaluation of Conventional and Unconventional Hydrocarbon Resources: Application to Low-Mature to Mature Source Rocks in the Liaohe Western Depression

Hydrocarbon potential evaluation is a high priority in oil/gas exploration which is significantly influenced by evaluation methods and subjective cognition. With the aim of quantitatively establishing a hydrocarbon generation and expulsion (HGE) model of source rocks, a data-driven approach is proposed based on abundant and readily available Rock-Eval/total organic carbon content (TOC)/vitrinite reflectance (VRo) datasets. This approach takes into account the original hydrocarbon generation potential (GPIo) and the loss of TOC. Hydrocarbon generation simulation was also adopted in this study. This data-driven method was applied to the Lower Paleogene Shahejie Formation (Es4), which has three sets of superior source rocks (average thickness &gt; 250 m, TOC &gt; 3%). The GPIo of the Es4 low-maturity source rock was 600 mg HC/g TOC. The initial maturity values of hydrocarbon generation and expulsion were 0.36% and 0.46%, respectively. The Gaosheng sub-member of the Es4 source rock had the largest amount of hydrocarbon generation but a limited amount of hydrocarbon expulsion, implying a favorable exploration of shale oil resources. By contrast, the values of the conventional, unconventional tight, and shale oil resource potentials of the Niuxintuo sub-member were 3.20 × 107, 7.70 × 107, and 5.93 × 108 t, respectively, indicating good prospects for tight oil and shale oil exploration. A comparison between the previous method and the data-driven method showed considerable differences in the restoration of GPIo and TOC, and both had their own limitations. This data-driven approach provides a quick and valid source rock evaluation method and can greatly enhance the accuracy of resource assessment.

Pore Structure and Its Controls of Shale in the Qingshankou Formation, Sanzhao Sag, Songliao Basin

The exploration and development of Gulong shale oil in the Songliao Basin has achieved a major breakthrough, with the result that a national shale oil demonstration area is being built. The shale in the Sanzhao Sag is abundant in organic matter and is an important replacement area. For this reason, it has recently become a focus for research and exploration. Compared with the Gulong Sag, the Qingshankou Formation in the Sanzhao Sag is relatively immature, and comparatively little is known about its pore structure. For this study, well ZY1, a key well in the Sanzhao Sag, was selected as the research object. Thin section observation, high-resolution field emission scanning electron microscopy, Modular Automated Processing Systemimaging, X-ray diffraction of whole rock and clay, TOC pyrolysis, and Low-pressure N2 adsorption were used to investigate the pore structure in the sag to determine the factors influencing pore development. The principal understandings are as follows: (1) The Qingshankou Formation in the Sanzhao Sag is predominantly clay shale, with a high content of clay minerals (32.8 to 70%) and TOC contents of 0.7 to 11%. These values indicate good hydrocarbon generation potential. (2) Interparticle pores, intraparticle pores, and organic matter pores are developed. Intergranular pores are the main type, mostly observed between granular minerals or between granular minerals and clays. Intraparticle pores are observed in pyrite mass and dissolved unstable minerals. Organic matter pores (OMP) occur in primary organic matter and migrate into solid bitumen. (3) The shale pores in the Sanzhao Sag are mainly H3-type slit pores, with specific surface areas of 5.4~22.9 m2/g and pore volumes of 0.03~0.07 cm3/g. Mesopores make the largest contribution to pore volume and specific surface area. Scanning electron microscope (MAPS) imaging shows that the pore size distribution of shale is mainly 20~30 nm and 100~200 nm and that large pores, especially pores of 100~200 nm and 1~2 μm, make the largest contribution to the facies. (4) The pore structure in the Sanzhao Sag is affected by mineral composition, abundance of organic matter, thermal evolution degree, and diagenesis. Organic-inorganic interactions influence and determine the pore structure characteristics of the Qingshankou Formation shale. This paper is intended to provide scientific guidance and technical support for evaluating the effectiveness of shale oil reservoirs and selecting sweet spots in the Sanzhao Sag.

Lithofacies and Shale Oil Potential of Fine-Grained Sedimentary Rocks in Lacustrine Basin (Upper Cretaceous Qingshankou Formation, Songliao Basin, Northeast China)

Shale oil has become a global hotspot of unconventional exploration and development. In this study, the latest drill core and experiment analyses of the Qingshankou Formation in the northern Songliao Basin were used to evaluate its lithofacies classification, sedimentary environment, pore types, pore-throat structure characterization, and shale oil potential. Lithofacies classification was determined according to the total organic carbon (TOC) content, sedimentary structure, and rock mineral content. Laminae genesis and micro-sedimentary structures indicate the deposition of fine-grained sedimentary rocks (FGSRs) in a semi-deep to deep lacustrine environment; however, evidence also suggests partial reworking by storm events and bottom current flows. FGSRs mostly comprise type I kerogen, with small amounts of type II1. The average vitrinite reflectance of the FGSRs was 1.37%, indicating middle to high stages of thermal maturation within the oil generation window. The N2 adsorption experiment indicated that silty mudstone (SM), silty fine mixed sedimentary rock (SFMR), and argillaceous fine mixed sedimentary rock (AFMR) had ink-bottle-shaped and slit-shaped pores, and the lithofacies were dominated by mesopores, accounting for 77.4%, 71.9%, and 80.8% of the total pore volume, respectively. Mercury injection capillary pressure analysis indicated that SM and SFMR had an average pore-throat radius of 0.01–0.04 μm, whereas AFMR and CM were dominated by nanopores, mainly distributed in the range of 0.004–0.0063 μm. Based on the comprehensive studies of TOC content, pore development, and brittleness, we concluded that organic-rich laminated SM and SFMR should be the focus of shale oil exploration of the Qingshankou Formation in the northern Songliao Basin, followed by organic-rich or organic-moderate laminated and layered AFMR, as well as calcareous fine mixed sedimentary rocks.

Characteristics and Influencing Factors of Multi-Scale Pore Structure Heterogeneity of Lacustrine Shale in the Gaoyou Sag, Eastern China

The success of shale oil exploration and production is highly dependent on the heterogeneous nature of the reservoir pore structure. Despite this, there remains limited research on the heterogeneity characteristics of pores at different scales in lacustrine shale oil reservoirs and the factors that impact them. This study aims to quantitatively characterize the multi-scale pore heterogeneity differences of the lacustrine shale found in the Funing Formation in Gaoyou Sag. Additionally, the study seeks to clarify the impact of the total organic carbon (TOC) and lithofacies type on pore structure heterogeneity. To achieve this, nitrogen adsorption, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), and other experimental means were adopted in combination with the fractal dimension model of FHH and capillary. The results show that the predominant lithofacies of the Funing Formation shale samples are mixed shale (MS) and siliceous shale (SS), with a limited presence of calcareous shale (CS). The micro-pores of lacustrine shale are dominated by inorganic mineral pores and fewer organic pores. Intragranular pores and clay mineral pores are two types of inorganic mineral pores that are widely found. Small pores (pore diameter &lt; 50 nm) make up 89% of the pore volume (PV) and 99% of the specific surface area (SSA). The fractal dimensions D1, D2, and D3 were calculated to characterize the roughness of the pore surface, the structural complexity of small pores, and the structural complexity of large pores (pore diameter &gt; 50 nm), respectively. The increase in the total organic carbon (TOC) resulted in a decrease in the D1, D2, PV, and SSA, while connectivity showed a slight improvement. The fractal dimension of shale across all lithofacies followed the pattern: D3 &gt; D2 &gt; D1. The pore structure is more complex than the pore surface, and the large pores showed a greater heterogeneity than the small pores. Among the three lithofacies, CS had the largest PV, SSA, D1, and D2, indicating the development of a more complex pore structure network. This expands the space required for shale oil occurrence. However, the connectivity of the CS lithofacies is the lowest among the three, which hinders shale oil production. Although the PV of SS is slightly lower than that of CS, its average pore diameter (AVE PD) and connectivity are significantly advantageous, making SS an ideal shale reservoir. This study provides an important reference for the reservoir evaluation required to better develop lacustrine shale oil around the world.

Control Effect of Deposition Processes on Shale Lithofacies and Reservoirs Characteristics in the Eocene Shahejie Formation (Es4s), Dongying Depression, China

The lacustrine fine-grained sedimentary rocks in the upper interval of the fourth member of the Eocene Shahejie Formation (Es4s) in the Dongying Depression are important shale oil exploration targets in Bohai Bay Basin. They are widely distributed and rich in organic matter. In this study, samples were observed under the optical microscope and FESEM, combined with geochemical test and physical property analysis to study the sedimentary characteristics and reservoir characteristics of them. Nine lithofacies are recognized based on the mineral composition, the content of organic matter and the beddings. The middle-high organic laminated calcareous fine-grained sedimentary rocks (LF1) and the middle-high organic laminated mixed fine-grained sedimentary rocks (LF2) resulted from seasonal sediment variations and settled by suspension in the deep lake. The middle-high organic flaggy mixed fine-grained sedimentary rocks (LF3), the middle-high organic flaggy calcareous fine-grained sedimentary rocks (LF4), the middle-high organic massive calcareous fine-grained sedimentary rocks (LF5) and the middle organic massive mixed fine-grained sedimentary rocks (LF6) were formed by redeposition. The low organic massive argillaceous fine-grained sedimentary rocks (LF7), the low organic massive felsic fine-grained sedimentary rocks (LF8) and the low organic massive mixed fine-grained sedimentary rocks (LF9) are affected by the terrigenous input events. The pore structures vary in different beddings which are influenced by the kinds and arrangement of minerals and particles. In the laminated lithofacies, the ink-bottle-shaped pores are dominant. In the flaggy and massive lithofacies, the ink-bottle-shaped pores and the slit-shaped pores coexist. LF1 and LF2 are the best target for shale oil exploration and the LF3, LF4, LF5 and LF6 are the second. The deposition processes control the lithofacies and reservoir characteristics of the fined-grained sedimentary rocks.

Lithofacies Characteristics and Their Effects on Shale Oil Enrichment: A Case Study from Shahejie Formation of the Qibei Sag, Bohai Bay Basin, China

The lithology and lithofacies assemblage of shale are highly complex and heterogeneous in the continental shale formations due to rapid changes in the sedimentary environment and source material, complicating the evaluation of shale oil enrichment areas, such as the member 3 of the Shahejie Formation in the Qikou sag, Bohaibay Basin, China. We used core observations and descriptions of well F39 × 1 and performed X-ray diffraction, scanning electron microscopy, nitrogen adsorption analysis, and nuclear magnetic resonance analysis to investigate the shale lithofacies characteristics and types in member 3 of the Shahejie Formation, and their effects on shale oil enrichment. The results showed the following. (1) The lithofacies are divided into four types according to the shale’s laminar structure, lithological characteristics, mineral composition, and organic matter content: thin laminar shale, thick laminar shale, massive mudstone, and argillaceous siltstone. These are divided into six subcategories. Each lithofacies has thin vertical layers. (2) The thin and thick laminar shale layers have favorable conditions for shale oil enrichment, such as a high total organic carbon content (TOC) (1.1–1.6%), many micropores (with the diameter of 0.5–2 µm) and fissures, a high residual hydrocarbon content (1.0–2.3 mg/g), and a good source-reservoir relationship, making them suitable for shale oil exploration. (3) The degree of lamina development influences the organic matter and residual hydrocarbon contents, the number of micropores, and the degree of shale oil enrichment. The semi-deep and deep lake facies are favorable areas for shale oil development.

Molecular Dynamics Simulation of Adsorption and Absorption Behavior of Shale Oil in Realistic Kerogen Slits

Exploring the occurrence of shale oil is of guiding significance to the exploration and recovery of shale oil. However, most studies focus on adsorption and neglect absorption or study it independently, which weakens the understanding of the coupling relationship between adsorption and absorption and the occurrence mechanism of shale oil in kerogen and its associated pores. Based on molecular dynamics (MD) simulation, the kerogen matrix with a smooth surface is constructed, and the general amber force field is adopted to calculate the adsorption and absorption of shale oil in a type II kerogen slit, and the influences of temperature, pressure, and pore diameter on the occurrence of shale oil are also discussed. Molecules absorbed in the kerogen matrix are mainly retained in the free space formed by the accumulation of aliphatic carbon. The effects of temperature on the distribution of shale oil in adsorption and absorption are opposite. High temperature improves the desorption of molecules from the adsorption sites and causes a lower adsorption and greater absorption. In contrast, pressure and pore diameter only slightly influence the distribution of shale oil. Unexpectedly, the result under aqueous conditions shows that the shale oil was absorbed quickly before the formation of water clusters. Once the water clusters are formed due to the strong hydrogen bonding and adsorbed near the N-, S-, and O-containing groups on the kerogen surface, the matrix gaps are blocked due to the size exclusion, and the absorption is suppressed. Additionally, we established the evolution of the ratio of free-adsorbed–absorbed oil at different temperatures and pressures, which provides a new idea and a new method for detecting the occurrence and mobility evaluation of shale oil under reservoir conditions.