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This study analyzes the bulk and molecular geochemical data of 56 core samples of the Eocene Qianjiang Formation, a confined source rock unit embedded with salt intervals formed in a hypersaline lacustrine setting in central China. These source rocks within a single evaporative cycle collected from a recent shale oil exploration well are highly laminated, consisting of both intra- and inter-salt shales. Both organic pores and matrix pores serve as storage for hydrocarbon generated from kerogen within the source rock. Because the contrast in density between kerogen and oil, conversion of kerogen to oil inevitably leads to the increase in pore pressure and oil expulsion from kerogen within the same source rock unit. Impregnation of source rocks by expelled oils from nearby mature source rocks or from the organic-rich laminae within the same source rock units leads to anomalous Rock-Eval pyrolysis data, characterized by an abnormally high S1 peak, a high Production Index (PI), a suppressed Tmax and other anomalies. It is contradictory that both Rock-Eval pyrolysis data and sterane isomerization ratios of the studied inter-salt shale samples indicate strong impact of allochthonous hydrocarbons in the source rocks, whereas most aliphatic biomarker parameters obtained from the solvent extracts of these shales still provide useful information on the vertical variation in organic source input and depositional environment of the host rocks. This study provides insights into the bulk and molecular geochemical data interpretation, particularly in the inter-salt shale oil system evaluation in inferring the prevailing directions and pathways of diagenetic fluid movement and hydrocarbon migration.

Oil mobility in liquid-rich shale is crucial for economic success of resource development. The characteristics of the host rock and the properties of oil fluids are two primary factors controlling fluid mobility. Organic geochemistry data allows examination of both resource potential and oil mobility. We propose data-driven empirical models in this paper to describe hydrocarbon resource potential with respect to oil mobility. The proposed methods were applied to a dataset collected from the Eocene-Oligocene Es3 and Es4 source rock units in four recent shale oil exploration wells in the Jiyang Super-Depression of the Bohai Bay Basin. The dataset, results from standard programmed pyrolysis of whole rock samples as well as solvent extracted replicates of 139 core samples, was studied to examine the source rock characteristics and shale oil resource potential. Bulk geochemical characteristics and thermal decomposition trends allow for sub-division of the samples into two groups; a) samples with high initial hydrogen index (>800 mg HC/g TOC) and average present day TOC of 4.07% from LY1 and NY1 wells in a distal facies; and b) samples with slightly lower initial hydrogen index (about 700 mg HC/g TOC) and average TOC of 3.11% from FY1 and L69 wells in a transitional facies. Three different categories of oil resource with respect to oil mobility can be defined: adsorbed, restricted and movable based on organic geochemical characteristics and their variations in the stratigraphic intervals represented by the samples in the four wells. We show that expulsion efficiency is a good indicator of hydrocarbon retention in source rock reservoir and that the two wells in the distal facies have higher total resource potentials with abundant movable oil resource than the two wells in the transitional facies. The total oil potential is separated into three types of oil resource to show oil mobility, thus providing more information for business decision.

Obtaining reliable total oil yield in a source rock from routine programed pyrolysis data represents a technical challenge for the characterization of source rocks in early mature and oil window due to strong interactions between bitumen and kerogen/rock matrix. A common laboratory solution for a robust estimate of total oil yield requires two pyrolysis experiments using a whole rock sample and a post-solvent extracted replicate. In this paper, we present a numerical solution that provides a reliable estimate of total oil yield directly from a single routine Rock-Eval experiment. In temperature domain, the thermally vaporized products from heavy oil and bitumen adsorbed to the organic matter and the pyrolyzed products from kerogen show a certain degree of overlap in the default temperature range of S2 peak. By transforming the routine Rock-Eval pyrogram (FID curve) into activation energy variable space, it allows for separation of the reactants into subgroups by their responses to ramping temperature. The thermally vaporized products can be then discriminated from the thermally pyrolyzed products based on the differences in their thermal stability and decomposition behaviour. The proposed method was applied to the source rock samples in the Eocene-Oligocene Shahejie Formation of Dongying Depression, Bohai Bay Basin, where programed pyrolysis results from whole rock samples and post-solvent extracted replicates were obtained. The case study suggests that (a) the two-step pyrolysis experiment approach may still under-estimate the total oil yield in case that solvent extraction treatment fails to remove all hydrocarbons in the sample; (b) the post-solvent extracted equivalent S2x values derived numerically from routine Rock-Eval analysis and those derived from post-extracted analysis are comparable with a correlation coefficient of 0.9766, suggesting numerical approach is as effective as additional laboratory experiment; and (c) the proposed approach can remove all petroleum in the sample numerically, thus providing an un-biased and robust estimate of total oil yield, a cost- and time-effective alternative to the traditional two experiment approach.

Source rock samples can be “contaminated” by expelled oils from nearby mature source rocks or from the organic-rich laminae within the same source rock units. The “contaminations” on the Rock-Eval samples could produce a false high S1 peak, a high Production Index (PI), a suppressed Tmax and other anomalies. Identifying the samples affected by expelled oils, assessing and correcting the impacts are crucial in source rock study for shale oil/shale gas resource evaluation. This study analyzes the Rock-Eval 6 results of 43 core samples from two recent shale oil exploration wells of the Eocene Qianjiang Formation, a confined source rock unit embedded with salt intervals formed in a hypersaline lacustrine setting in central China. The geochemical anomalies of the affected samples are shown through the available samples in this study. Criteria for identifying the affected samples are discussed, and impacts on the conventional Rock-Eval parameters and subsequent estimation of kinetic parameters presented. This study provides insights into Rock-Eval data interpretation, particularly in source rock evaluation for estimating shale oil resources.

Petrology and Rock-Eval analyses have been conducted in the lower third and upper fourth members (lower Es3 and upper Es4) of the Shahejie Fm source rock intervals in well Fanye1 in the Dongying Sag, Jiyang Depression, Bohai Bay Basin, eastern China. The organic matter in rocks intersected by this well is dominated by lamalginite and bituminite, and most samples contain Type I or II kerogen. Microfacies A–H has been identified according to their organic-mineral composition and structure using polished thin sections under microscopy. The form and location of hydrocarbon residue occurrences (mainly as solid bitumen with fluorescence) are different in those microfacies: microfacies A, which is dominant in well Fanye 1, is calcareous mudstone without lamination, and the hydrocarbon residue is dispersed through the rock, with some being present in subtle microfractures. Microfacies B and F are mostly composed of shale, with adsorbed hydrocarbon indicated by fluorescence along mineral grains. Microfacies C is laminated argillaceous carbonate, with hydrocarbon residue mainly occurring in thin microfractures along the bedding plane. Microfacies D and E are mainly carbonate, and microfacies D is laminated with micrite and sparite, and hydrocarbon residue occurrence is not only in the microfractures along the bedding, but also in the micropores among the grains in the sparite layers, which is the main place for hydrocarbon residue occurrence in microfacies type E without lamination. Microfacies G and H are both micrite. Microfacies G shows bioturbation and hydrocarbon residue occurs within small, irregular microfractures along the bedding planes and pores. Only a little solid bitumen without fluorescence has been observed in microfacies H. The Rock-Eval oil saturation index (OSI) (S1 × 100 / TOC) value is variable because of the different characteristics of these hydrocarbon residue occurrences. OSI values in microfacies A are normally high (74.8–242.8 mg HC/g TOC, average of 117.2 mg HC/g TOC), and likely much higher if microfractures develop (> 200 mg HC/g TOC). OSI values (averaging 43.7 mg HC/g TOC) are lowest in microfacies F because of adsorption on the shales, and OSI values are the highest in microfacies D (371.3 mg HC/g TOC) and E (199.9 mg HC/g TOC) since the hydrocarbon residues are stored both in microfractures and pores between the grains. Both OSI values are high in microfacies G and H because of low TOC content. The combination of petrographic and OSI analysis appear to be a promising tool for characterizing shale oil systems.

This article presents a novel numerical decomposition method based on generation kinetics for studying oil composition characteristics from S1 peak of single heating rate pyrolysis of source rock samples. Furthermore, phase behavior and PVT analysis were introduced in the calculation to make a full correction for evaporative loss of gaseous and light hydrocarbon in S1 during coring and sample storage. Special programed pyrolysis results of twenty-eight core samples, along with a routine source rock screening pyrolysis dataset of 68 samples, from a recent shale oil study well of the Eocene Qianjiang Formation in Jianghan Basin, China were analyzed to demonstrate the application of proposed methods. We showed that (a) by reassembling corresponding activation energies, the original S1 curve can be split into groups of similar thermal evaporative property, resulting in a composition classification of free hydrocarbons in S1 when it was converted back to temperature domain; (b) a full correction on the gaseous and light hydrocarbon loss in S1 permits a more precise estimation of oil composition as well as total resource; (c) the resulting oil composition grouping provides information for inferring the fraction of extractable hydrocarbon; d) oil composition varies considerably among the samples within a stratigraphic interval of 20 m. Samples from intra salt organic-rich lamina show different compositional characteristics with much less abundance in gaseous and volatile oil compounds; while samples from inter salt interval contain large portion of volatile and light oil, indicating a promising production zone.