The pore fluid occurrence predominantly restricts shale oil production. Few studies have addressed both pore oil and water concurrently. In an effort to delineate the distribution of pore fluids within shale oil reservoirs, this study collected diverse shale samples from the Qingshankou Formation in the Sanzhao Sag, Songliao Basin, China. The in-situ pore fluids were initially resurrected under equilibrium moisture conditions and subsequently saturated with light oil. A comprehensive suite of analytical techniques was employed in tandem, encompassing total organic carbon (TOC), Rock-Eval, X-ray diffraction (XRD), scanning electron microscopy (SEM), low-temperature nitrogen adsorption-desorption, and nuclear magnetic resonance (NMR). The occurrence characterizations of pore fluids were clarified by NMR T₁–T₂ spectra across various states, shedding light on the governing factors. A pattern of pore-fluid occurrence in shale oil reservoirs was proposed. Results indicate that NMR T₁–T₂ combined with water and oil restoration effectively assesses the distribution of in-situ pore fluids. Capillary-bound water primarily contributes to pore fluids, with nearly half being depleted at the as-received state. Shale oil mainly comprises capillary-bound oil, succeeded by adsorbed and movable oil. The alterations in shale oil occurrence characteristics are synchronous with the depletion of pore fluids. NMR T₁–T₂ primarily detects the adsorbed oil in shale pores, whereas Rock-Eval is capable of quantifying oil adsorbed on pore surfaces and absorbed within organic matter. NMR T₁–T₂ offers a more precise technique for quantitatively evaluating shale pore fluids. Micropores (<25 nm) and minipores (25–100 nm) are primarily saturated with capillary-bound water, accompanied by a minor fraction of adsorbed oil. Capillary-bound and movable oil are primarily distributed within mesopores (100–1000 nm) and macropores (>1000 nm), respectively. Consequently, adsorbed oil is significantly influenced by pore water, followed by capillary-bound oil, while movable oil remains largely unaffected. Felsic-rich (FR) shales may represent the optimal lithology for shale oil enrichment, characterized by the development of interparticle pores, a lower Brunauer-Emmett-Teller (BET) specific surface area, and abundant meso- and macropores. These insights into the characteristics of pore fluids in shale oil reservoirs could bolster shale oil exploration in the Sanzhao Sag.

Connate water strongly restricts shale gas enrichment and production, and most artificially injected water is confined in shale pore networks owing to low water recovery during hydraulic fracturing, which leads to a more complex pore water distribution. However, previous studies have focused on the water vapor sorption of gas shales rather than liquid pore water. This study clarifies the occurrence and distribution of pore water and the controlling factors by conducting thermogravimetry (TGA) under liquid water saturation and water vapor sorption experiments on four gas shales from the Wufeng Formation in South China. Nuclear magnetic resonance (NMR) T₂ and T₁–T₂ technologies were used to monitor the dynamic changes and states of moisture, and the microscopic pore structures during water vapor sorption were detected using low-temperature nitrogen adsorption-desorption. The results indicate that TGA is adequate for determining the adsorbed, bound, and movable water contents. These four gas shales are characterized by high adsorbed and movable water contents, and some bound water. The adsorbed water primarily occurs in tiny pores (<100 nm), controlled by organic matter, followed by clay minerals. The movable water, typically associated with quartz, primarily exists in pores of >100 nm, particularly macropores of >1000 nm. The bound water predominantly correlates with pores ranging from 10 to 2000 nm in clay minerals. The water vapor sorption process of the gas shale is well clarified. Water molecules primarily adsorb on the clay mineral's hydrophilic surface, followed by oxygen functional groups in the organic matter. Therefore, clay minerals control water vapor sorption at low relative humidity (RH <0.75), whereas organic matter primarily affects vapor sorption at high RH. The TGA of liquid water-saturated gas shales can clarify the water distributions in full-scale pore networks, whereas the water vapor sorption method primarily discloses the moisture in small nanopores (<100 nm) but ignores most bound and movable water. This paper provides insight into liquid water distribution and occurrence states within shale pore networks, contributing to a better understanding of gas–water–rock interaction systems in-situ and hydraulic fracturing shale gas formations.

Prediction of production decline and evaluation of the adsorbed/free gas ratio are critical for determining the lifespan and production status of shale gas wells. Traditional production prediction methods have some shortcomings because of the low permeability and tightness of shale, complex gas flow behavior of multi-scale gas transport regions and multiple gas transport mechanism superpositions, and complex and variable production regimes of shale gas wells. Recent research has demonstrated the existence of a multi-stage isotope fractionation phenomenon during shale gas production, with the fractionation characteristics of each stage associated with the pore structure, gas in place (GIP), adsorption/desorption, and gas production process. This study presents a new approach for estimating shale gas well production and evaluating the adsorbed/free gas ratio throughout production using isotope fractionation techniques. A reservoir-scale carbon isotope fractionation (CIF) model applicable to the production process of shale gas wells was developed for the first time in this research. In contrast to the traditional model, this model improves production prediction accuracy by simultaneously fitting the gas production rate and δ¹³C₁ data and provides a new evaluation method of the adsorbed/free gas ratio during shale gas production. The results indicate that the diffusion and adsorption/desorption properties of rock, bottom-hole flowing pressure (BHP) of gas well, and multi-scale gas transport regions of the reservoir all affect isotope fractionation, with the diffusion and adsorption/desorption parameters of rock having the greatest effect on isotope fractionation being D*/D, P_L, V_L, α, and others in that order. We effectively tested the universality of the four-stage isotope fractionation feature and revealed a unique isotope fractionation mechanism caused by the superimposed coupling of multi-scale gas transport regions during shale gas well production. Finally, we applied the established CIF model to a shale gas well in the Sichuan Basin, China, and calculated the estimated ultimate recovery (EUR) of the well to be 3.33 × 10⁸ m³; the adsorbed gas ratio during shale gas production was 1.65%, 10.03%, and 23.44% in the first, fifth, and tenth years, respectively. The findings are significant for understanding the isotope fractionation mechanism during natural gas transport in complex systems and for formulating and optimizing unconventional natural gas development strategies.

Low-to-medium maturity shale oil resources hold significant potential, but their economic accessibility is limited by low porosity, low permeability, and a low proportion of movable oil. In-situ conversion technology can crack organic matter and in-place oil into lighter molecules, enhancing oil and gas mobility and improving recovery rates. The success of this approach depends on dynamically evaluating the amount of movable shale oil during in-situ conversion. This study targets the lower submember of the fourth member of the Eocene Shahejie Formation (Lower Sha4 Member) in the Damintun Sag, Bohai Bay Basin, China. Through thermal simulation experiments, organic geochemical experiments, and nuclear magnetic resonance experiments, shale residual oil evaluation, organic matter hydrocarbon generation process evaluation, and dynamic evaluation of immovable oil were carried out. By integrating numerical simulations of the temperature field with the experimental results, a dynamic evaluation method for movable resources in shale during in-situ conversion was established. The findings indicate that the conversion rates of kerogen-to-oil and kerogen-to-gas first increase and then gradually stabilize as thermal maturity increases, with oil generation reaching its peak when the vitrinite reflectance reaches 1.0%. Long-term preserved shale samples were identified to contain immovable oil, the content of which increases with maturity before peaking and then declining. In-situ conversion of low-to-medium maturity shale in the upper part of the model can significantly increase movable oil resources in a year, potentially reaching the levels of extractable medium-to-high maturity shale. This work presented a crucial approach for assessing and improving In-situ conversion technology, providing a means of maximizing economic feasibility.

Characterizing the microscopic occurrence and distribution of in-situ pore water and oil is crucial for resource estimation and development method selection of shale oil. In this paper, a series of nuclear magnetic resonance (NMR) experiments were conducted on shales from the Gulong Sag, Songliao Basin, China, at AR, WR-AR, WOR-AR, Dry, SO, and WR states. In-situ pore water and oil were reconstructed after WOR-AR. An improved T₁–T₂ pattern for shale oil reservoirs comprising water and oil was proposed to classify and quantitatively detect pore fluids at different occurrence states. The total and free oil contents derived from NMR T₁–T₂ spectra at AR states were found to correlate well with those from multistage Rock-Eval. Moreover, the NMR-calculated total and free oil are generally larger than those measured from multistage Rock-Eval, whereas adsorbed oil is the opposite, which implies that adsorbed, bound, and movable oils in shale pores can be accurately and quantitatively detected via NMR, without absorbed hydrocarbons in kerogen. As per the NMR T₂ and T₁–T₂ spectra at WOR-AR state, the microdistributions of in-situ pore water and oil were clearly demonstrated. Adsorbed, bound, and movable oils primarily occur in the micropores (<100 nm), mesopores (100–1000 nm), and macropores (>1000 nm), respectively, whereas capillary-bound water is primarily correlated with micropores. Thus, the microscopic occurrence and distribution of adsorbed oil are remarkably affected by pore water, followed by bound oil, and movable oil is hardly affected. This study would be helpful in further understanding the microscopic occurrence characteristics of pore fluids in-situ shale oil reservoirs.

The occurrence characteristics of shale oil are of great significance to the movability of shale oil. In this study, the occurrence characteristics of oil in the shale matrix at Funing Formation shale in Subei Basin were quantitatively evaluated by organic geochemistry and microscopic pore structure characterization experiments. The Multiple Isothermal Stages Pyrolysis (MIS) experiment results show that the content of total oil, adsorbed oil, and free oil in the shales are 3.15–11.25 mg/g, 1.41–4.95 mg/g, and 1.74–6.51 mg/g, respectively. among which the silicon-rich shale has the best oil-bearing. The relative content of free oil shows an increasing trend in pores with pore diameters greater than 3 nm. When the relative content of free oil reaches 100%, the pore size of silicon-rich shale is about 200 nm, while that of calcium-rich shale, clay-rich shale, and siliceous mixed shale is about 10 nm. The occurrence law of adsorbed oil is opposite to that of free oil, which indicates that shale oil will occur in the pores and fractures in a free state in a more extensive pore size range (> 200 nm). This study also enables us to further understand the occurrence characteristics of shale oil under the interaction of occurrence state and occurrence space.

Shale oil can be extracted from shale by using interconnected pore networks. The migration of hydrocarbon molecules within the shale is controlled by pore connectivity. However, assessing the pore connectivity of shale oil reservoirs is uncommon. To characterize pore connectivity and clarify its controlling factors, this study used spontaneous imbibition (SI) combined with nuclear magnetic resonance (NMR) T₂ and T₁-T₂ technologies on shale oil reservoirs selected from the Shahejie Formation in the Dongying Sag, Bohai Bay Basin. According to the findings, the SI processes of shales include fast-rising, slow-rising, and stable stages. The fast-rising stage denotes pore connectivity. The shales studied have poor connectivity, with lower imbibition slopes and connected porosity ratios, but large effective tortuosity. During the SI process, micropores have the highest imbibition saturation, followed by mesopores and macropores. Furthermore, n-dodecane ingested into micropores appears primarily as adsorbed, whereas n-dodecane appears primarily as free states in mesopores and macropores during the SI process. The pore connectivity of the shales under study is primarily controlled by inorganic minerals. Quartz and feldspar develop large and regular pores, resulting in better pore connectivity, whereas clay minerals and calcite with plenty of complex intragranular pores do not. Organic matter negatively influences pore connectivity because the dissolution of calcite by organic acid produced during hydrocarbon generation leads to a more complex and heterogeneous pore structure. This study sheds light on the pore connectivity and controlling factors of the shale oil reservoir and aids in the understanding of shale oil mobility.