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To study the impact of faults on the enrichment and mobility of shale oil in the Gulong area, representative rock samples were selected in this paper. Based on geochemical data and chemical kinetics methods, coupled with shale oil enrichment and mobility analysis techniques, the shale oil generation quantity and in situ oil content were evaluated from the perspectives of shale oil generation and micro migration, and the mobility of shale oil was revealed. At the same time, the hydrocarbon expulsion efficiency (HEE) of shale was qualitatively and quantitatively characterized, combined with the development of faults. The research results indicate that the study area mainly develops organic-rich felsic (ORF)/organic-containing felsic (OCF) shale, their proportion in both wells exceeds 65%, and the resource amount is the largest in this type of lithofacies. The development of a fault controls the enrichment of shale oil, and the in situ oil content and oil saturation index (OSI) of the shale in well Y58, which is close to the fault, are significantly worse than those in well S2. Well Y58 has 9.52 mg/g and 424.83 mg/g TOC respectively, while well S2 has 11.34 mg/g and 488.73 mg/g TOC respectively. The fault enhanced the migration of shale oil, increasing the efficiency of oil expulsion. As a result, the components with weak polarity or small molecules, such as saturated hydrocarbons and low carbon number n-alkanes, are prone to migration, reducing the mobility of shale oil. [ABSTRACT FROM AUTHOR]

The features and formation stages of natural fractures have significant influences on the fracturing of shale reservoirs and the accumulation of oil and gas. The characteristics and evolution of tectonic fractures in the Lianggaoshan Formation in Northeast Sichuan were investigated based on outcrops, drill cores, geochemical data, and acoustic emission test results. Our results demonstrated that the fracture types of the Lianggaoshan Formation were mainly low-degree bedding-slip fractures, followed by high-degree through-strata shear fractures and vertical tensile fractures. The influences of strike-slip faults on the fractures were stronger than those of thrust faults; fractures in thrust faults were concentrated in the hanging wall. The densities of tensile and shear fractures were inversely proportional to the formation thickness, while the density of interlayer slip fractures was independent of the formation thickness. The density of tectonic fractures was proportional to the quartz content. The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), (2) Middle Himalayan tectonic movement (48~32 Ma), (3) Late Himalayan tectonic movement (15 Ma~4 Ma). Fractures greatly improve the oil and gas storage capacity and increase the contents of free and total hydrocarbons. At the same time, they also reduce the breakdown pressure of strata. This study facilitated the prediction of the fracture distribution and oil and gas reservoirs in the Lianggaoshan Formation and provided references for the selection of favourable areas for shale oil and the evaluation of desert sections in the study area. [ABSTRACT FROM AUTHOR]

To accurately evaluate the shale oil resources in the Funing Formation of the Gaoyou Sag, Subei Basin, light and heavy hydrocarbon correction models of S1 were developed based on the rock pyrolysis of liquefrozen, conventional, and oil-washed shales. The improved ΔlogR technique was applied to establish the TOC, S1, and S2 logging evaluation methods. The results showed that the S2 values after oil washing were significantly lower than before. The difference between these two S2 (ΔS2) values is the heavy hydrocarbon correction amount of S1, which is about 0.69 S2. There was almost no loss of light hydrocarbons during liquefrozen shales' pyrolysis tests; the ratio of liquefrozen to conventional S1 values is the light hydrocarbon correction factor, which is about 1.67. The corrected S1 is about 3.2 times greater than the conventional shale-tested value. The S1 and TOC are obviously "trichotomous"; a TOC greater than 1.5% and corrected S1 larger than 4.0 mg/g corresponds to the enriched resource. The logging estimated results show that the total shale oil resources in the E1f2 of the Gaoyou Sag are about 572 million tons, of which the enriched resource is about 170 million tons. [ABSTRACT FROM AUTHOR]

To investigate the brittleness of shale and its influencing factors, triaxial rock mechanics experiments, combined with X-ray diffraction, total organic carbon (TOC) measurement, rock pyrolysis, and scanning electron microscopy, were conducted on shales from the Jurassic Lianggaoshan Formation in the Sichuan Basin. BI1, based on the elastic modulus and hardness, BI2, based on mineral composition, BI3, based on strength parameters, and BI4, based on the post-peak energy of shale, were calculated. Additionally, the effects of mineral composition, density, hardness, and organic matter on the brittleness of shales were analyzed. The results show that the shale mineral compositions were dominated by quartz (mean of 45.21%) and clay minerals (mean of 45.04%), with low carbonate mineral contents and high TOC contents. The stress–strain curve showed strong brittleness characteristics. When comparing different evaluation methods, the brittleness evaluation method based on the stress–strain curve (damage energy) was found to be more effective than the mineral fraction and strength parameter methods. The higher the density and hardness, the more brittle the shale. The higher the organic matter and quartz content, the less brittle the shale. The brittleness of sub-member I of the Lianggaosan Formation in Well XQ1 was higher than that of sub-members II and III. This study investigated the brittleness of lacustrine shale and its influencing factors, which is beneficial for the development of shale oil in the Sichuan Basin. [ABSTRACT FROM AUTHOR]

• An innovative fluid identification method for the NMR T 2 spectrum using mixed Gaussian function decomposition was developed. • The 1D T 2 projection spectrum was introduced to establish the relationship between the 2D T 1 -T 2 spectrum and the 1D T 2 spectrum. • Unveiled an inconsistent linear correlation between 1D and 2D NMR signal amplitudes for various fluids. • Bound water, bound oil, adsorbed oil, and movable oil occur within pores of varying sizes. Nuclear magnetic resonance (NMR) has become a crucial technique for determining complex fluid occurrence characteristics. However, the overlap of fluid signals limits the application of the one-dimensional (1D) T 2 (transverse relaxation time). Conventional methods are unable to accurately detect fluid signals that overlap entirely and cannot directly determine the petrophysical significance of each component spectrum. Leveraging the additional T 1 (longitudinal relaxation time) information of two-dimensional (2D) NMR T 1 -T 2 , this study introduced a novel T 2 spectra fluid identification method using the mixed Gaussian function. Six states of T 2 and T 1 -T 2 experiments were conducted on shale samples, including as-received (AR), water restoration of AR (WR-AR), water–oil restoration of AR (WOR-AR), oil-washed and dry (dry), oil-saturated (SO), and water-saturated (SW). By introducing the T 2 projection spectrum, linear relationships between the 1D and 2D NMR signal amplitudes of various fluids were established to help separate the overlapping signals in the T 2 spectrum. The results have demonstrated an inconsistent linear correlation between the 1D and 2D NMR signal amplitudes of various fluids, influenced by fluid composition and occurrence state. The conversion coefficient of adsorbed oil is 1.745 times higher than that of bound oil in the SO state. The adsorbed-to-bound ratio conversion coefficient was proposed as an additional input in the mixed Gaussian function to identify overlapping fluids in the oil–water coexistence state. The conversion coefficient of bound water determined by peak area analysis of 1D and 2D NMR before and after water restoration validated the identification results. The pore water altered the occurrence characteristics of oil, reducing the conversion coefficient. Furthermore, the pore-size characteristics of fluid occurrence were described. Compared with the conventional method, the proposed method bridges the gap between 1D and 2D NMR, significantly enhancing the accuracy and reliability of fluid identification by T 2 spectra and providing new insights for NMR fluid evaluation in shale reservoirs. [ABSTRACT FROM AUTHOR]

To better understand the pore structure and fractal character of lacustrine shales and their influence on liquid hydrocarbon occurrences, in this study, a total of 29 lacustrine oil-bearing shale samples collected from the Shahejie Formation in the Dongying Sag, Bohai Bay Basin, were investigated based on nitrogen adsorption (NGA) analysis combined with TOC, Rock-Eval pyrolysis, X-ray diffraction (XRD), and field emission-scanning electron microscopy (FE-SEM) experiments. The relationships among the compositions (TOC, minerals, and oil content), pore structures, and fractal dimensions of the lacustrine shale samples were discussed. The results showed that the adsorption and fractal characteristics of lacustrine oil-bearing shales differ at relative pressures of 0-0.1 and 0.5-1. Two corresponding fractal dimensions D 1 and D 2 were determined by the FHH model according to the nitrogen adsorption branches. Specifically, D 1 varies from 2.4292 to 2.6109 (mean 2.5245), and D 2 varies between 2.4680 and 2.8535 (mean 2.6889). The specific surface area (SSA) ranges from 1.512 m2/g to 34.002 m2/g, with an average of 13.656 m2/g, the total pore volume is between 6.0 × 10-3 cm3/g and 48.4 × 10-3 cm3/g (mean 24.5 × 10-3 cm3/g), and the average pore diameter is in the range of 4.22 nm to 19.57 nm (mean 9.35 nm). Both D 1 and D 2 increase with increasing SSA and increase with decreasing average pore diameters but have no correlation with pore volume. Moreover, D 1 and D 2 exhibit positive relationships with clay minerals and negative correlations with carbonate minerals (calcite and dolomite). The relationship between fractal dimensions ( D 1 and D 2 ) and TOC contents is expressed as a U-shaped curve, characterized by the minimum D values at approximately 3% TOC. The shale oil content is controlled by the pore structures and fractal dimensions, and lacustrine shales with lower SSAs and smaller fractal dimensions would have more free oil. Therefore, lacustrine shales in the oil window with TOC contents ranging from 2% to 4% are probably the preferred shale oil exploration target in the Shahejie Formation, Dongying Sag, Bohai Bay Basin. The results indicate that fractal analysis can provide insight into the pore structure characteristics and oil storage capacity of lacustrine shales. [ABSTRACT FROM AUTHOR]

Abstract Porosity is a key parameter for the evaluation of potential shale oil and gas resources. Low-field nuclear magnetic resonance (NMR) is a rapid technique for measuring shale porosity without causing damage to the testing samples. Previous NMR methods for porosity characterization are mainly based on the NMR T 2 distribution of saturated oil shale, but for shales with high total organic carbon (TOC) and clay mineral contents, not all signals of NMR detection originate from the pore fluid. Nine continental shales in Damintun Sag were selected and subjected to pyrolysis, X-ray diffraction (XRD), mercury injection capillary pressure (MICP), weighing before and after fluid saturation, and NMR tests to improve the accuracy of NMR porosity measurements. According to the NMR T 2 distribution and T 1 –T 2 map of shale with different oil contents (original, extracted, and saturated oil states), we revealed that the non-fluid signals (kerogen and structural water) accounted for 15.77%–43.10% (with a mean of 28.87%) of saturated oil shale. A stronger NMR signal intensity was observed for the extracted shale with higher TOC and clay mineral contents. A ΔT 2 distribution of oil present in the pores of oil-saturated shale was constructed based on the difference between the oil-saturated shale and extracted shale and was combined with the calibration equation of oil (the relationship between oil volume and its NMR signal intensity) to directly evaluate the porosity. The porosity that was calculated based on the ΔT 2 distribution versus the weighing method had an absolute error of ≤0.7%, and the relative error was <10%. Compared with the previous NMR method, the new method does not require optimization of the NMR parameters and considers the contribution of organic matter and clay minerals to NMR signals, which is more suitable for the porosity evaluation of shales with high TOC and clay mineral contents. The results of this study are helpful for NMR characterization of the porosity in shales. Highlights • The NMR T 2 , T 1 –T 2 characteristics of organic-rich continental shale with different oil contents were discussed. • Non-fluid components (kerogen and structural water) have high NMR signals in the saturated oil shales was revealed. • A new NMR method for measuring the porosity of organic-rich shale was established. [ABSTRACT FROM AUTHOR]

Abstract Shale oil reservoirs characterized by complex pore structures typically contain a wide pore size range from nanometers to millimeters. The pore size distribution (PSD) is one of the most critical parameters affecting fluid storage and transport properties in shale oil reservoirs. Quantitatively and accurately determining PSD is of great importance for evaluating the shale oil occurrence state and movable fluid volume. In this study, four major techniques, including nitrogen adsorption (NA), scanning electron microscopy (SEM), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR), were adopted to determine pore sizes in ten shale oil reservoir samples from Dongying sag, Bohai Bay basin, China. NMR T 2 spectra were converted to PSDs by using a new subsection calibration method based on the NA and SEM measurements; using the linear and power exponent conversion models, these two models are compared. The results show that the subsection calibration is an effective method for shale NMR T 2 spectrum conversion. Shale oil reservoir T 2 spectra can be converted to full-scale PSDs by combining NA micropore (<100 nm) PSDs and SEM mesopore (100 nm–1000 nm) PSDs using linear and power exponent models. The power exponent model is more useful for determining the approximate initial transverse surface relaxivity (ρ 2,0) values for the shale samples. However, if the calibration PSDs are not sufficient, the average conversion coefficient (51.295, in this study) of the linear model is recommended to determine an approximate NMR PSD. The results also indicate that there is a wide range of pore sizes from micropores to macropores (>1000 nm) in shale oil reservoirs; however, they are mainly connected by small-scale throats. Therefore, the comprehensive characterization of shale oil reservoir pore structures may be efficiently and accurately determined by a combination of NMR and MICP. Highlights • An accurate NMR test method for revealing shale pore structure was established. • A new subsection calibration method for NMR T 2 spectrum conversion was constructed. • A more useful power exponent model between pore sizes and T 2 values was determined. [ABSTRACT FROM AUTHOR]

In tight shales, occurrence characteristics limit oil migration and recovery. This paper proposes an innovative approach based on experimental and theoretical models to investigate the oil occurrence mechanism in nanoporous shales. Thermogravimetry (TG) and nuclear magnetic resonance (NMR) tests were conducted to investigate the migrations and distributions of adsorbed, irreducible, and movable oils. Furthermore, the oil micro-occurrence characteristics within shales were quantitatively clarified using the theoretical equation for the adsorption ratio. Lacustrine shales with different lithofacies from Dongying Sag, Bohai Bay Basin, China, were evaluated as a case study. The results showed that adsorbed, irreducible, and movable oils occur in different pore sizes. The adsorbed oil is primarily saturated in micropores (<0.1 μm) and mesopores (0.1–1 μm) but hardly in macropores (>1 μm), characterized by an average density of around 1.4974 g/cm3 and a mean adsorption thickness of approximately 0.723 nm at a temperature of 60 °C. The irreducible oil predominantly occurs in mesopores, whereas the movable oil primarily exists in mesopores and macropores, and the weight ratio rapidly increases with increased pore size. Additionally, the NMR T 1 –T 2 patterns of the adsorbed, irreducible, and movable oils were reported, and these patterns can directly reveal the states of oil micro-occurrence in shale pore-fracture systems. This study gives substantial insights into the oil occurrence mechanisms in nanoporous shales. • An innovative method evaluating the micro-occurrence of shale oil was developed. • The mean density and adsorption thickness of adsorbed oil at 60 °C were disclosed. • The NMR T 1 – T 2 patterns of the adsorbed, irreducible, and movable oils were presented. [ABSTRACT FROM AUTHOR]

Samples from seven major exploration wells in Biyang Depression of Henan Oilfield were compared using low-temperature nitrogen adsorption and shale oil adsorption experiments. Comprehensive analysis of pore development, oiliness and shale oil flowability was conducted by combining fractal dimension. The results show that the fractal dimension of shale in Biyang Depression of Henan Oilfield was negatively correlated with the average pore size and positively correlated with the specific surface area. Compared with the large pore, the small pore has great fractal dimension, indicating the pore structure is more complicated. Using S1 and chloroform bitumen A to evaluate the relationship between shale oiliness and pore structure, it was found that the more heterogeneous the shale pore structure, the higher the complexity and the poorer the oiliness. Clay minerals are the main carriers involved in crude oil adsorption, affecting the mobility of shale oil. When the pore complexity of shale was high, the content of micro- and mesopores was high, and the high specific surface area could enhance the adsorption and reduce the mobility of shale oil. [ABSTRACT FROM AUTHOR]

Following shale gas, shale oil has become another highlight in unconventional hydrocarbon exploration and development. A large amount of shale oil has been produced from a host of marine shale in North America in recent years. In China, lacustrine shale, as the main source rock of conventional oil and gas, should also have abundant oil retained in place. In this study, geochemical and geologic characteristics of lacustrine shale from Es sub-member in Bonan sag were characterized by using total organic carbon (TOC), Rock-Eval pyrolysis, X-ray diffraction, and Δlog R method. The results show that the Es sub-member shale have TOC contents ranging from 0.5 wt.% to 9.3 wt.%, with an average of 2.9 wt.%. The organic matter is predominantly Type I kerogen, with minor amounts of Type II1 kerogen. The temperature of maximum yield of pyrolysate ( T ) values ranges from 424 to 447 °C, with an average of 440 °C, and vitrinite reflectance (Ro%) ranges from 0.7% to 0.9%, indicating most of shales are thermally mature. The dominant minerals of Es shale in Bonan sag are carbonates (including calcite and dolomite), averaging 51.82 wt.%, and the second minerals are clay (mostly are montmorillonite-illite-mixed layer and illite) and quartz, averaging about 18 wt.%. Finally, its shale oil resources were evaluated by using the volumetric method, and the evaluation result shows that the shale oil resource is up to 5.94 billion tons, and mostly Class I resource. Therefore, the exploration of the lacustrine shale oil of Es in Bonan sag should be strengthened. [ABSTRACT FROM AUTHOR]

The occurrence and mobility of oil obtained from shales are primarily controlled by the pore–fracture networks of the shales. To clarify the distributions and characteristics of the type, morphology, and size in lacustrine shale pores, shale samples obtained from the Shahejie Formation, Dongying Sag, Bohai Bay Basin in China were examined using argon ion milling and scanning electron microscopy. In this study, pores were mainly classified as interparticle pores, intraparticle pores, and fractures and further classified into 14 types, comprising intraparticle pores (7 types), interparticle pores (6 types), and fractures, based on the differences in their components. Interparticle pores have more complex morphologies than intraparticle pores and fractures. Complex shapes characterize the interparticle pores between quartz granules and at the edges of feldspar granules. Intraparticle pores mainly contribute to mesopores and then to macropores, while interparticle pores behave in the opposite manner. Micropores are primarily derived from the intraparticle pores present in clay aggregates and dissolution pores present in calcite or dolomite granules. However, macropores mainly come from the interparticle pores present within or at the edges of quartz granules; consequently, siliceous-rich shales may be the favorable shale oil reservoirs called interlayer shale oil. Moreover, organic-rich calcareous shales with numerous large dissolution pores can become optimal self-generation and self-storage shale oil reservoirs. This study gives insight into the evaluation of shale oil exploration and development in the Dongying Sag in the Bohai Bay Basin. • Fracture, 7 types of intra- and 6 types of interparticle pores were observed. • The morphology and size of each type of pore were well revealed. • Micropores mainly come from intraparticle pores in clay and carbonate minerals. • Macropores primarily come from interparticle pores associated with quartz granules. [ABSTRACT FROM AUTHOR]

Shale oil resources are found in the argillaceous dolomite in the Xingouzui Formation of the Jianghan Basin. The grading evaluation criteria based on the oil content was established to discuss the shale oil potential. The parameter of hydrocarbon potential index, ( S 1 + S 2 )/TOC × 100, suggests that the hydrocarbon potential of the argillaceous dolomite becomes lower significantly with the type of kerogen changing from I to III. However, a corresponding decrease in the amount of residual hydrocarbon ( S 1 /TOC) is within a small range, because the argillaceous dolomite with I and II 1 kerogen (especially I kerogen) have relatively larger hydrocarbon expulsion amount. For shale oil exploration, besides type I source rocks, source rocks with II 1 and II 2 kerogen should also be focused. However, source rocks with III kerogen bear no exploration significance owing to the low hydrocarbon generation capacity and unfavorable molecular configuration. According to the relationship between S 1 and TOC, combined with parameter of the relative oil content, the shale oil resources can be divided into four classifications: enriched resources ( S 1 > 4 mg/g and S 1 /TOC > 1), moderately enriched resources (1 mg/g < S 1 < 4 mg/g and S 1 /TOC > 1), less efficient resources (1 mg/g < S 1 < 4 mg/g and S 1 /TOC < 1), and ineffective resources ( S 1 < 1 mg/g and S 1 /TOC < 1). The continuous distribution of the oil content of the argillaceous dolomite in the Lower Xingouzui Formation can be obtained using the method of Δlog R . The enriched or moderately enriched resources are primarily distributed in the argillaceous dolomite with kerogen types I and II 1 . In addition, moderately enriched resources also exist in the argillaceous dolomite with kerogen type II 2 in the middle and bottom of the Lower Xingouzui Formation, but the distribution is more dispersed. [ABSTRACT FROM AUTHOR]

The occurrence states (adsorbed or free) directly control the transport and production of shale oil, and free oil is the most common potential product available using existing technologies. A variety of theories and experimental methods have been developed to estimate the adsorbed and free oil amounts in shale pore-fracture systems, however, it is difficult to clarify the microdistribution characteristics of shale oil in in-situ pore systems using these methods. In the study described here, by integrating experimental and theoretical models, an effective method was developed to reveal the microdistribution of oil confined in nanoporous shales from the Dongying Sag, in the Bohai Bay basin, China. Centrifugation–nuclear magnetic resonance (NMR) experiments were combined with the modified Langmuir equation, and then applied to estimating amounts of adsorbed and free oil. And the microdistribution characteristics of shale oil were then analyzed by the adsorption ratio theoretical model. Furthermore, the mechanisms of controlling the adsorbed, free amounts and microdistribution of shale oil were also discussed. The primary results demonstrated that the modified Langmuir equation (Langmuir-like equation) was an effective and accurate technique for evaluating the adsorbed and free oil amounts in shales. We estimated that adsorbed and free oil amounts ranged from 5.8023 to 29.7995 mg/g, and from 3.9510 to 25.6410 mg/g, respectively, at a temperature of 20 °C, while the adsorbed oil weight ratios were 0.2778–0.7023 (mean 0.5438). The average value of the adsorbed oil density was approximately 2.0231 g/cm³, which was 2.6994 times that of the free oil. The average adsorbed layer thickness was 0.7433 nm, which equaled nearly two molecular diameters. The adsorbed and free oil microdistribution was clearly described by the adsorption ratio theoretical model and the T₂ spectrum. The adsorbed oil was mainly confined to micropores, while free oil was stored in meso- and macropores—and that pore microstructures affected shale oil microdistribution characteristics. The amount of adsorbed oil was mainly controlled by micropore volume and specific surface area, while the amount of free oil was closely associated with total volume of the larger pores. We also noted that the more complex the pore structure, the lower the free oil content and the higher the adsorption ratio. The amount of adsorbed oil was closely related to the shale composition, and increased with TOC content. The amount (ratio) of adsorbed oil also increased with increasing clay mineral content, and was negatively proportional to the quartz + feldspar content. The authors are confident that the study described in this paper has delivered new insights into the microdistribution of adsorbed and free oil in shale pore-fracture systems. • An innovative method evaluating the microdistribution of adsorbed and free oil were developed. • The average value of the adsorbed oil density and adsorbed layer thickness were revealed. • The adsorbed and free oil microdistribution in shale pore systems was clearly described. [ABSTRACT FROM AUTHOR]

The occurrence characteristics of pore fluids restrict shale oil recovery. Various approaches have been proposed to analyze the microdistribution of shale oil, but they are limited by the simultaneous characterization of the occurrence of oil and water within shale pore networks. This study conducted a range of nuclear magnetic resonance (NMR) T 2 and T 1 –T 2 measurements on the shales at different states, sampled from the Paleogene Funing Formation in the Gaoyou Sag, Subei Basin. A novel water and oil restoration method was introduced to restore pore fluid distributions in shales. The T 1 –T 2 pattern with eight regions was determined for shale oil reservoirs. The pore oil and water in different states were quantitatively calculated using NMR T 1 –T 2 spectra and compared with the results from Rock-Eval. In addition, the occurrence pattern of pore fluids in shales was proposed. The primary results indicated that free oil derived from multistage Rock-Eval is generally lower than that determined using the NMR T 1 –T 2 spectrum. The NMR T 1 –T 2 spectrum specializes in detecting the adsorbed, capillary-bound, and movable oil in pore systems but is limited in quantitatively identifying oil absorbed in organic matter. The occurrences and distributions of pore oil and water in different states can be effectively revealed by the T 1 –T 2 spectrum. Capillary-bound water is predominantly associated with micropores (<100 nm) and, to a lesser extent, with mesopores (100–1000 nm); a similar pattern is observed for adsorbed oil. As a result, adsorbed oil is significantly restricted by pore water. Capillary-bound oil primarily occurs in mesopores, whereas macropores (>1000 nm) are saturated with movable oil. Hence, the distribution of capillary-bound oil is still affected by pore water, whereas movable oil is not. The authors are confident that the results presented in this study offer innovative insights into the occurrence and distribution of pore fluids in shale pore networks. • A novel experimental approach to examine shale pore fluids was proposed. • Pore water and oil in different states were accurately evaluated by NMR T 1 –T 2. • The difference between NMR T 1 –T 2 and Rock-Eval in detecting shale oil was clarified. • Micro-occurrence pattern of pore fluids in shale was expounded. [ABSTRACT FROM AUTHOR]

Few 1D T 2 and 2D T 1 - T 2 Nuclear magnetic resonance (NMR) studies have focused on oil-bearing shales with complex constituents and a deeper understanding of the NMR relaxation behaviors of oil confined in shale is needed. In this paper, a series of T 2 and T 1 - T 2 NMR experiments were performed on oil-bearing shale and its components (clay minerals and kerogen) to obtain the T 1 - T 2 fluid typing chart and analyze the adsorbed and free oil in shale. The results were as follows: five types of water (bound, adsorbed, free, crystal and structural water) in clay minerals were qualitatively identified and described by the specific T 2 to T 1 / T 2 ratio values, and T 1 - T 2 maps were used to qualitatively indicate the clay type. The T 1 - T 2 fluid typing chart containing the signatures of 8 proton populations in oil-bearing shale was defined and included bulk liquid, macropore (>1000 nm) oil, nanopore (<1000 nm) oil, and free water in clay minerals or kerogen, shale pore water, bound water in clay minerals, kerogen and crystal water. Adsorbed oil was mainly confined in nanopores, especially micropores smaller than 100 nm, while free oil composed of movable and irreducible oil was predominant in mesopores (100–1000 nm) and macropores. Furthermore, the proportion of irreducible oil gradually decreased and that of movable oil gradually increased from mesopores to macropores. The results demonstrate that the T 1 - T 2 NMR technique may be an effective method for the assessment of fluid distributions and proton mobility and has potential applications for the characterization of shale oil occurrence states. • Five types of water in clay minerals were qualitatively identified by the specific T2 to T1/T2 ratio values. • The T1-T2 fluid typing chart containing the signatures of 8 proton populations in oil-bearing shale was defined. • Shale oil occurrence states in different size pores were qualitatively revealed. [ABSTRACT FROM AUTHOR]

An interval of black shales deposited from Precambrian to lower Cambrian from the southwestern depression of the Tarim basin (SDTB) was systematically evaluated in terms of hydrocarbon potential, organic matter, depositional environment and oil-source relationship. The shales have good TOC contents (up to 3.15%) but low S 1 +S 2 values (<0.03 mg/g), indicating the source rocks are currently at high thermal maturities. The relationship between pristane/n-C 17 and phytane/n-C 18 indicates the kerogen was oil prone and dominant by algal input. Furthermore, the depositional environment had relatively moderate salinity and stratified water environment indicated by G/C 30 H ratios (0.15–0.24). The high algal input may have enhanced TOC preservation under reducing conditions reflected by high dibenzothiophene content and low pristane/phytane ratios (mean 0.79). Thus, these source rocks may have generated a significant amount of oil during their geological history. Additionally, in view of the molecular geochemistry indicators, the extracts of black shales hold marked differences with the Cambrian-Ordovician end-member oils, but are quite similar to oils in the northeastern portion of the SDTB. It means that the lightly explored SDTB may contain significant hydrocarbon resources, and coeval source rocks in the ultra-deep portion of the basin may have contributed to the prolific petroleum resources in the Tarim Basin. • The hydrocarbon potential of Precambrian-Lower Cambrian black shales in the Southwestern Depression from the Tarim Basin has been discussed for the first time. • The input of organic matter and the sedimentary environment of the source rocks have been interpreted. • The affinity between shales and crude oils in study area has been investigated. [ABSTRACT FROM AUTHOR]

The article discusses the critical role of shale oil mobility evaluation in the E2S4 Enrichment Segment of Damintun hydrocarbon expulsion in China. The need to base the classification of shale oil and gas resources on the enrichment degree and the workability of oil and gas is outlined. The determination of the standard of the Damintun shale oil mobility by the hydrocarbon expulsion threshold is also tackled.

The article presents a study to compare the hydrocarbon potential of Devonian-Lower Carboniferous and Cretaceous source rocks system of the Williston Basin. It attempts to establish the evaluation criteria of shale oil for Bakken Formation. It evaluates the organic matter abundance of the Bakken Shale on account of an improved model.

The article focuses on a study about shale oil exploration in China. It provides details about use of rock pyrolysis in conducting lacustrine shale from Qingshankou Formation member 1 of Songliao basin and Shahejie Formation of Bohai Bay basin as well as marine shale from lower Cambrian Niutitang Formation of Qiannan depression. Information about micro-pore volume and total organic carbon content is presented.

Abstract To evaluate the effects of the composition, laminar structure and burial depth on pore volumes connected by pore-throats of different sizes in a shale oil reservoir, the Es1x formation in the Raoyang Sag of the Bohai Bay Basin was selected as an example. The effects of component contents, laminar structure and burial depth on pore volumes connected by pore-throats with widths of <100 nm, 100–1000 nm and 1000–10000 nm were discussed based on total organic carbon (TOC), X-ray diffraction, low-temperature N 2 adsorption and mercury intrusion porosimetry methods. The results show that pore volumes connected by pore-throats with widths of <100 nm decrease with increasing contents of TOC and carbonate and increase with increasing clay content. The pore volumes connected by pore-throats with widths of 100–1000 nm initially decrease with increasing quartz + feldspar content and then increase when the content exceeds 20%. The pore volumes connected by pore-throats with widths of 1000–10000 nm increase with increasing TOC content, and then decrease when TOC content exceeds 2.5%. They also exhibit a negative relationship with clay content. The pore volumes connected by pore-throats with widths of <100 nm are initially similar in nonlaminated and laminated samples with equivalent burial depths and decrease with increasing burial depth. However, at depths in excess of 3100 m, the connected pore volumes in the nonlaminated samples increase with increasing burial depth and become larger than those of the laminated samples. The pore volumes connected by pore-throats with widths of 100–1000 nm in the nonlaminated and laminated samples are similar, and there are no obvious changes with increasing burial depth. The pore volumes connected by pore-throats with widths of 1000–10000 nm in the nonlaminated and laminated samples are also similar and decrease with increasing burial depth at burial depths less than 3100 m, and then connected pore volumes in the laminated samples increase with increasing burial depth at burial depths exceeding 3100 m. The connected pore volumes in the laminated samples are larger than those in the nonlaminated samples at burial depths exceeding 3400 m. Highlights • Various components influence the connected pore volumes in a shale oil reservoir. • The connectivity features of nonlaminated and laminated samples are different. • Compaction and hydrocarbon generation both affect the connected pore volumes. [ABSTRACT FROM AUTHOR]

This article quantitatively investigated the microscopic pore structure of the Eocene argillaceous dolomite reservoir from the Jianghan Basin in China to further the understanding of shale oil and gas storage mechanism in these rocks, considering that extensive studies have been conducted on the shale reservoir but seldom focused on argillaceous dolomite reservoir. Image analysis technology (containing Areal porosity method, CT reconstruction calibration method and focused ion beam-scanning electron microscope) and intrusive method including mercury intrusion porosimetry were used to discuss the size, spatial distribution and connectivity of the pores, as well as to reveal the contribution rate of the pores to porosity. Dolomite and clay minerals are the main minerals in the samples (including mudstones, argillaceous dolomite and dolomite mudstones), with the average values are 27.8% and 28.5% respectively. Inorganic pores (mineral-associated pores) rather than organic pores (organic matter-hosted pores) are dominant in the argillaceous dolomite reservoir, which contain intercrystalline pores, intergranular pores and dissolved pores. The inorganic porosities calibrated by SEM range from 7.82% to 18.58%, close to the measured porosities. The argillaceous dolomites mainly develop intercrystalline pores in the dolomite mineral with good connectivity, while mudstones or dolomite mudstones mainly contain intergranular pores in the clay minerals with poor connectivity. Large throats always distribute in the parts where pores are well developed and connected. The connectivity of the pores in the argillaceous dolomite improves with the increase of the dolomite mineral content. The argillaceous dolomites have relatively high porosity containing more macropores while mudstones have lower porosity occupied by much more micropores. Pores with relatively larger throat radii contribute a larger fraction of the porosity of the argillaceous dolomite, while pores with smaller throat radii mainly contribute to porosity in the mudstones. These characteristics may be beneficial for understanding reservoir mechanism of argillaceous dolomite reservoir. [ABSTRACT FROM AUTHOR]

Characterization of microscopic pore system of organic-rich shales is of great importance for understanding the occurrence mechanism and flow behavior of shale oil. Currently, there are numerous studies on pore structure characteristics of shales, but research about the coupling relationship between shale material composition and its microscopic pore system is relatively weak. In this paper, we conducted mercury injection capillary pressure (MICP), Low-temperature N 2 adsorption (LTNA) and broad ion beam scanning electron microscope (BIB-SEM) experiments combined with low-field nuclear magnetic resonance (NMR) to quantitatively characterize the full-scale pore structure of typical lacustrine shales in the northern Songliao Basin, China, and analyzed the coupling relationship between multi-scale pore structure and material composition. Results show that these shales are mainly develops inorganic interparticle pores related to clay minerals, and a small amount of organic matter pores were also present. A pore size classification scheme for I-micropore (0–20 nm in diameter), II-micropore (20–50 nm), mesopore (50–150 nm), macropore (>150 nm) within shales was proposed by combining fractal theory with MICP tests. The full-scale characterization of shale revealed that it mainly developed micropores and mesopores, and the pore size was distributed primarily in the region less than 150 nm. The pore specific surface area of these shales was relatively high with a mean value of 20.76 m2/g and mainly controlled by clay minerals. The coupling relationship analysis of different pore types and shale material composition reveals that clay minerals and carbonate minerals govern the development of II-micropores and macropores respectively, whereas organic matter controls the development of I- micropores. It's worth mentioning that organic matter inhibits the formation of mesopores, and the microfractures formed in the shale are dominated by shrinkage OM pores. Based on our observations, the applicability of different experimental methods for characterizing the pore structure of shales is also summarized. The difference between these experiments revealed that the method proposed in this paper is an effective way to characterize the full-scale pore structure of shale. • Inorganic interparticle pores associated with clay minerals were main pore types of typical lacustrine shales. • A pore size classification scheme that divided the pore scale of shale into four types was proposed by combining fractal theory with MICP tests. • An NMR-based full-scale pore size distribution of shale was constructed in combination with results of nitrogen adsorption and BIB-SEM images analyses. • The coupling relationship between multi-scale pore structure and material composition was analyzed with respect to various pore structure parameters of lacustrine shale. [ABSTRACT FROM AUTHOR]

In this paper, a new method called sweet spot index (SSI) is proposed by the combination of shale oil mobility and shale reservoir fracability to predict the vertical distribution of shale oil sweet spots using conventional logs. In the SSI method, logging evaluation models for TOC, S 1 (volatile petroleum), and mineral content are initially established. Mobile oil content is obtained by subtracting the amount of adsorbed oil from the total oil content, which is the S 1 value after the recovery of light and heavy hydrocarbons. The adsorbed oil content is calculated based on the oil adsorption model established by a stepwise pyrolysis experiment. The formation fracability is estimated by a combination of estimates of brittle mineral content and Young's modulus. Formations with higher brittleness and lower Young's modulus are considered better simulation candidates. The SSI value is the product of the normalized mobility and the fracability index, which minimizes the section of just an organic matter sweet spot (i.e., high oil content) or an inorganic sweet spot (i.e., easily fractured) and has the advantage of accurately predicting its vertical distribution. In the case study, the new method is successfully implemented to predict sweet spots of the Es3L (lower sub member of the third member of the Eocene Shahejie Formation) in the Bonan Sag, Bohai Bay Basin, China. The lower limit value of SSI is set to 0.1 based on its relationship with shale oil production. The effectiveness, reliability and adaptability of the SSI method have been verified by three wells in the Bonan Sag. • The organic and inorganic heterogeneous evaluation methods were established by conventional logs and measured core data. • An adsorbed oil model was established using the stepwise heating pyrolysis experiment. • A new sweet spot index (SSI) model was developed by the combination of shale oil mobility and shale reservoir fracability. • The lower limit value of the SSI was set to 0.1 based on the shale oil production data in Bonan Sag. [ABSTRACT FROM AUTHOR]

With the consumption of conventional petroleum resources, the exploration and development (E&P) of unconventional hydrocarbons in recent years have supplemented the shortage of petroleum resources to some extent. Shale gas has been successfully exploited from marine strata in southern China; however, E&P of lacustrine shale oil resources with large resource potentials have not reached expectations. This paper reviews the progress of exploration for lacustrine shale oil in China and discusses the geochemical features of shale and shale oil from a key shale oil exploration area in the Jiyang Depression to accelerate lacustrine shale oil exploration and to provide an improved understanding of prospective shale oil locations. For the first time, shale oil exploration, shale geochemistry, and geological features for nine major lacustrine sedimentary basins in China are summarized explicitly, and a detailed comparison analysis with Bakken, Eagle Ford, and Permian shales is conducted. The geochemical data (more than 600 analytical data points) and shale oil geochemical characteristics from four key shale oil exploration wells in the Jiyang Depression were analyzed in detail and were also used to analyze the prospect of shale oil exploration in this area. Finally, the research status of shale oil "sweet spot" evaluation is summarized, and key research directions needing further work are presented. In China, many wells have accidently produced certain amounts of shale oil from mudstone/shale fractures. The exploration and geochemical characteristics of lacustrine shales indicate not only that shale oil is a rich resource but also that it shows good exploration breakthrough potential, such as intersalt shale oil with an OSI (oil saturation index) generally higher than 300 and located in the Jianghan Basin. Samples from four key wells reveal geochemical features of lacustrine shale in ES 3 (the third member of the Paleogene Shahejie Formation) and ES 4 (the fourth member of the Paleogene Shahejie Formation) that demonstrate a high richness of organic matter in the ES 3 and ES 4 shales from the Jiyang Depression. Kerogen types are mainly I-II 1 , in a low maturity-mature stage, and OSI values are higher than 100; shale oil flows are also being produced from shale fractures. In general, the progress of exploration for lacustrine shale oil in China has been unsatisfactory in recent years. We believe that shale oil mobility and shale fracability are vital factors for shale oil exploitation, which should be strengthened and further studied. • The exploration progress of lacustrine shale oil in China is reviewed. • Shale oil resources are huge and have good potentials for exploration breakthroughs in China. • Jiyang Depression ES shale have a high TOC content, with type I-II 1 kerogen, within the marginal mature to mature stage. • Shale oil mobility and shale fracability property are vital factors. [ABSTRACT FROM AUTHOR]

Shale oil is a promising alternative unconventional energy to conventional fossil fuels. Although some studies have been conducted on total oil content, little work to date was performed on sorbed versus free oil, which is essential for estimating shale oil reserves. This study proposed a sorbed oil model insights from the contribution of oil absorption in kerogen (Abs k), oil adsorption on organic pores (Ads k), and oil adsorption on clay pores(Ads c). The model innovatively considers the effect of thermal maturation on kerogen sorption and the proportion of clay pores hosting adsorbed oil (f). A case study shows that the Abs k ranges from 250 to 80 mg/g TOC in the vitrinite reflectance range of 0.5%–0.89%, while Ads k is 16.5–115.58 mg/g TOC because organic pores are not well developed. For clay pores, the oil adsorption capacity is 1.8 mg/m2 and f is mainly controlled by the oil saturation. At the early oil window, oil sorption associated with kerogen dominated, thus free oil instead of total oil contents should be considered when selecting favorable areas. The proposed model is useful to our understanding of the shale oil occurrence mechanism and provides a new way of estimating sorbed oil contents at different maturity. [Display omitted] • A novel sorbed oil model is proposed by combining kerogen absorption, organic pore adsorption, and clay pore adsorption. • Thermal maturation has a great effect on kerogen sorption oil capacity. • Free oil instead of total oil contents should be considered in the selection of shale oil sweet spots at the early oil window. [ABSTRACT FROM AUTHOR]

Determination of the in situ hydrocarbon content and occurrence characteristics of shale oil reservoirs is crucial for reserve prediction and efficient development. Although many scholars have studied the fluid saturation of conventional coring shale using solvent and thermal extraction methods, with time consuming and only volumes or mass of oil and water were given, which could not reveal the occurrence characteristics of oil and water in samples. This study proposes a two-dimensional (2D) nuclear magnetic resonance (NMR) T1–T2 mapping method to systematically assess the in situ water and oil content, distribution, and their evaporative loss laws of preserved shales. Sixty preserved shales with different maturities were selected from the first member of the Qingshankou Formation in the northern Songliao Basin, China. Each preserved sample was divided into two parts and analyzed using a high-frequency (22 MHz) NMR and Dean–Stark extraction respectively. Furthermore, a time-elapsed NMR T1–T2 mapping was performed on a preserved shale core sample after varying the exposure times in an open environment. Results show that T1–T2 mapping can be used to determine the porosity, water and oil contents, and saturations of preserved shales. Oil content measured using T1–T2 mapping was consistent with that obtained by Dean–Stark extraction, with a correlation coefficient (R2) as high as 90% when crude oils of varying maturities were used for NMR calibration.The T1/T2 of oil inpreserved shale showed a negative trend with maturity, and the T2 of oil was often higher than that of water, indicating oil is enriched in the relative macropores. After exposing the preserved shale to open air for 150–200 h, 1) the total loss ratio of oil and water was approximately 80%; 2)the fluid evaporation loss rate follows the orders: oil > water and fluids in larger pores > smaller pores; 3)the free oil content decreased by approximately 92%, whereas the absorbed oil content varied slightly. As a nondestructive, rapid, and minimal sample preparation method, 2D NMR can efficiently assess both fluids content and distribution of a core sample in only 5 min, thus displaying its great advantages and applications for preserved shales with fast fluid evaporation to determine the in situ fluid content. • NMR T1–T2 mapping and Dean–Stark methods derive consistent oil content when NMR signals were calibrated by different matured crude oils. • Loss rates of water, total oil, free oil, and absorbed oil after long-term exposure of preserved shale are quantified. • NMR T1-T2 mapping is highly recommended to assess saturation and distribution of in situ fluids in preserved shale core samples for its high efficiency. [ABSTRACT FROM AUTHOR]

The ‘saline mudstone’ sequence of the Paleogene Shahejie Formation in the Dongpu Depression of Bohai Bay Basin is a major source rock for conventional hydrocarbons. However, shale oil, having a density of ~ 0.9 g/cm 3 and a viscosity of ~ 21 mPa·s, has also been discovered and is being produced from these mudstones. To better understand the occurrence of such shale oil, geochemical petrological and mineralogical investigations were carried out on a suite of saline mudstone samples by using Rock-Eval, X-ray diffraction and SEM. The Shahejie Formation samples analyzed in the current study are characterized by type II kerogen with lesser amounts of types I and III, such that petroleum generation ranges from ‘fair’ to ‘excellent’ in general terms. With the exception of Es1 (uppermost member), which is immature to marginally mature for oil generation, the sequence studied ranges from ‘mature for oil generation’ to ‘mature for wet gas generation’. On the basis of vitrinite reflectance data, the most prospective depths for shale oil/condensate generation are between ~ 2300 and 4000 m depth in area studied. The saline mudstones comprise mainly clay minerals, followed by carbonates, quartz and feldspar. Based solely on the ‘brittle mineral index’, the amounts of carbonate and quartz in many of the samples lead to a similar, or greater suitability for hydraulic fracturing than for many Haynesville, Woodford and upper Bakken shales. SEM studies show that abundant micro-fractures commonly occur in the mudstones and these include tectonic fractures, bedding plane fractures, shrinkage fractures, and over-pressured fractures. For the Es3 M (middle third member) unit, shale oil prospectivity is likely to be enhanced around the towns of WL (Wenliu), LT (Liutun) and HBZ (Hubuzhai), due to the increased frequency of tectonic fractures, which would contribute to oil storage and flow. Mineral interparticle, mineral intraparticle and organic matter pores are well developed in the rocks studied. Mineral dissolution has created secondary pores in some areas, such that reservoir capacity is increased. The increased concentration of organic acids between 2800 and 3500 m is likely to lead to enhanced shale oil prospectivity. The micro-fractures and dissolution pores are probably the main reservoirs for shale oil accumulation. The association of these features with saline facies potentially offers an exploration tool for further shale oil occurrences in the studied area, as well as in other areas containing similar lithologies. [ABSTRACT FROM AUTHOR]

• Four methods for quantifying the hydrocarbon content of preserved shale are compared. • Hydrocarbon loss caused by sample crushing and analysis delay time is quantified in Rock–Eval 6 analysis. • NMR T 1 -T 2 mapping is highly recommended to determine the primary in situ oil content of preserved shales. An accurate determination of in situ hydrocarbon (oil) content is critical for the assessment of shale oil plays in terms of their total resources in place and recovery potential. Although correction of light hydrocarbon loss to the Rock–Eval S1 parameters on conventional core and cuttings samples has been recently attempted using preserved (e.g., sealed or pressure–preserved) cores, hydrocarbon evaporation loss during sample preparation and delay time before the actual commencement of Rock–Eval analysis has not received sufficient attention. In this study, a combination of petrophysical and geochemical techniques including Dean–Stark extraction, hydrogen nuclear magnetic resonance (1H-NMR) T 1 - T 2 mapping, thermal desorption–gas chromatography (TD–GC) analysis, and Rock–Eval programmed pyrolysis were used in parallel on a set of 30 preserved shale cores to determine their total hydrocarbon contents. The preserved shale cores were analyzed in large pieces (e.g., 3–5 cm in size) by the former two petrophysical methods while using fine powder (e.g., <60 mesh) by the latter two thermal analytical methods. The total free hydrocarbon contents (equivalent of Rock–Eval S1) determined on the studied lacustrine shale samples with a R o ranging from 1.00% to 1.51% followed the order of Dean–Stark (average 10.27 mg/g) ≈ NMR (10.34) ＞ TD–GC (6.65) ＞ Rock–Eval (3.93). The core crushing and grinding process required for both TD-GC and Rock–Eval pyrolysis analyses was found to cause a loss of approximately 35% to the in situ hydrocarbons. In addition, Rock–Eval analysis delay time (of 5 min) could lead to another 25% reduction to the total free hydrocarbons. In combination, sample preparation and analysis delay resulted in up to 60% reduction to the Rock–Eval S1 peaks for the preserved shale cores, and a 30% loss to the liquid (C 6+) hydrocarbons in particular. To the best of our knowledge, this is the first reported observation that in situ light hydrocarbon contents can be severely underestimated by Rock–Eval and TD–GC analyses using powdered forms of preserved core samples. The extents of light hydrocarbon loss in conventional cores have been underestimated using the Rock–Eval S1 difference between preserved shale and its long–duration exposed replicates. Hence, when quantifying the hydrocarbon contents of the preserved shale samples, techniques utilizing larger rock pieces are highly recommended. [ABSTRACT FROM AUTHOR]

• Accurate GIP content was obtained based on the pressure-holding coring technique. • The accuracy of traditional methods and the CIF model were compared and verified. • The CIF model can provide the most accurate estimation results of GIP content. • Carbon isotope fractionation during complete degassing was observed and characterized. • △ δ 13C 1 (fractionation amplitude) was demonstrated to indicate gas-adsorbed ratio. Gas-in-place (GIP) and gas-adsorbed ratio are crucial parameters for resource potential assessment and production strategy optimization. Although various methods have been proposed to evaluate these two parameters, none have been widely recognized due to a lack of convincing comparison and validation. In this study, we established a GIP content calculation method by summing five gas components in the pressure-holding coring (PHC) technique: lost gas during retrieving, extracted gas during depressurization, lost gas during surface exposure, degassed gas, and residual gas. The GIP content of the four pressure-holding shale cores retrieved from the Longmaxi Formation of Lu-2 well, Sichuan Basin, China, ranges from 6.46 cm3/g to 10.58 cm3/g, which is used for comparing and verifying theoretical methods. The comparison results show that traditional methods, including the USBM, polynomial fit, ACF, and MCF methods, failed to accurately evaluate GIP content due to their defects in the theoretical foundation and boundary conditions settings. The carbon isotope fractionation (CIF) model derived on a rigorous theoretical basis and equipped with variable boundary conditions achieves the highest accuracy when evaluating the GIP content. Furthermore, the CIF model can determine the gas-adsorbed ratio, another critical parameter that traditional methods cannot obtain; the calculated gas-adsorbed ratio of five shale samples from the Lu-2 well is between 11.15% and 24.56%, with an average of 17.10%. With the help of the CIF model, we confirmed the general pattern of isotope fractionation during shale gas degassing and discussed the limitation and potential of two empirical parameters, δ 13C 1 of the first sample and △ δ 13C 1 (the difference in δ 13C 1 value between the last and first sample), in indicating the adsorbed gas content. [ABSTRACT FROM AUTHOR]

Characterizing free and adsorbed hydrocarbon is crucial for the resources assessment and mobility evaluation of shale oil plays. The complex feature of hydrogen-bearing components in shale reservoirs requires new analytical methods to study the occurrences of different states of hydrocarbons. In this study, forty core samples from five shale oil research wells in the Jiyang Depression of China were analyzed using various analytical tools including nuclear magnetic resonance (NMR) T 1 -T 2 mapping, Leco total organic carbon (TOC) analysis, routine and special programmed Rock-Eval pyrolysis, solvent extraction and fractionation, as well as mercury injection capillary pressure (MICP) experiments. Additional experiments were conducted on a powdered shale for NMR T 1 -T 2 maps under four states: as-received, after being dried at 110 °C, after special programmed pyrolysis to 350 °C, and after solvent extraction. The results showed that residual water signals in the NMR T 1 -T 2 map disappeared after being dried at 110 °C. Free oil signals decreased dramatically when the sample was thermally treated to 350 °C, while adsorbed oil signals decreased sharply after solvent extraction. A good accordance was observed between the organic hydrogen T 2 spectra and three modes of Rock-Eval pyrograms, representing free hydrocarbons, adsorbed hydrocarbons, and hydrocarbons from kerogen/bitumen decomposition. A positive correlation was also found between the intensity of NMR T 1 -T 2 map signals and the free and adsorbed hydrocarbon contents from geochemical analysis. T 2 cut-off values of adsorbed hydrocarbons and free hydrocarbons were determined to be 0.2 ms and 1 ms, respectively. Core samples with a high oil saturation index, porosity, and relative content of hydrocarbons display a low T 1 /T 2 ratio indicative of a high shale oil mobility. As a complementary method to the Rock-Eval analysis, NMR T 1 -T 2 mapping is a non-destructive technique for the characterization of adsorbed and free hydrocarbons at the core scale with limited sample preparation. The results of this study are helpful for NMR characterization of shale reservoirs. • The organic hydrogen T 2 spectra were conducted from the NMR T 1 -T 2 maps of shale. • Two T 2 cut-off value sets were determined: >1 ms for free oil, at 0.2–1 ms for adsorbed oil, and <0.2 ms for kerogen remnant. • Good positive correlations between NMR T 1 -T 2 map and Rock-Eval pyrograms were revealed. • The T 1 /T 2 ratio of free oil could be used as an indicator of shale oil mobility. [ABSTRACT FROM AUTHOR]

• The temperature threshold (T OK) of the S2oil and cracking hydrocarbons was determined. • The control factors of T OK was revealed. • A prediction model for T OK was established. • A fast method for evaluating the total oil yield using a single routine Rock-Eval experiment on as-received shales was proposed. Shales in the early maturity and oil window stages contain a considerable amount of heavy hydrocarbons (S 2oil) having strong interactions with kerogen/rock that make the accurate measurement of total oil (total extractable organic matter) more difficult from the routine Rock-Eval experiment. In this study, a fast method for evaluating the total oil yield using a single routine Rock-Eval experiment on as-received shales is proposed. First, the temperature threshold (T OK) of the S 2oil and cracking hydrocarbons were determined by combining the pyrograms of the as-received shale with a solvent-extracted replicate. Then, the total oil yield was directly derived from the hydrocarbons evaporate at a temperature below than T OK in a routine Rock-Eval experiment. The results show that the T OK value is controlled by the sample's maturity and pore structure. The higher the maturity, the larger the specific surface area and the smaller the pore size, the greater the T OK. A prediction model of T OK was proposed based on the sample's production index (PI). The total oil yields estimated by the two methods of both the T OK prediction model and the average T OK value (465 °C) are consistent with those obtained by Jarvie (2012) using the thermal-extraction method with correlation coefficients of 0.983 and 0.9548, respectively. Compared with the previous methods, the single routine Rock-Eval experiment method proposed in this study is convenient and not requires an extraction experiment. In addition, there are archived routine pyrolysis data available that can be used to directly calculate the total oil yield based on the temperature threshold. [ABSTRACT FROM AUTHOR]