Shale Oil Production Research Articles

A physical constraint-based machine learning model for shale oil production prediction

Shale oil has become a crucial unconventional resource, bolstering energy supply security, and it is important to accurately predict shale oil production dynamics. However, traditional prediction methods are faced with the challenges of large data fluctuations and numerous interference factors, which make accurate prediction difficult. This paper introduces a deep learning approach, specifically a physical constraint-based convolutional neural network combined with long short-term memory and attention mechanism (CNN-LSTM-AM), to predict shale oil production dynamics. Initially, the correlation analysis method is used to analyze the correlation strengths of features with the prediction target, and the data that are most strongly correlated with the daily oil production are screened out and preprocessed. Key features are then extracted; that is, the CNN layer's output is fed into the LSTM layer, the output of which informs a fully connected layer for time-series production predictions. The model integrates an AM to concentrate on vital data aspects. In the “five-linear flow” formula, the imbibition is hard-coded into the shale oil production prediction model. Physical constraints are introduced into the model. Data driven and empirical formulas are used to introduce a loss function as a constraint condition in the training process of a machine learning model to improve the interpretability and predictive ability of the model. During the tuning phase, Bayesian optimization is used to fine-tune the model's hyperparameters. Shapley additive explanation and accumulated local effects analyses are used to further assess and quantify the significance of the essential parameters, thus optimizing the prediction effectiveness.

Geologic characteristics, exploration and production progress of shale oil and gas in the United States: An overview

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle–Late Devonian, Early Carboniferous (Middle–Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian–Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and “shale reservoirs” are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×1012 t and 290×1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the “shale revolution”, the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007–2023, shale oil and gas production in the United States increased from approximately 11.2×104 tons of oil equivalent per day (toe/d) to over 300.0×104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Shale oil recovery by CO2 injection in Jiyang Depression, Bohai Bay Basin, East China

Laboratory experiments, numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO2 injection. The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO2 injection, and the influences of CO2 pre-pad on shale mechanical properties. Numerical simulations were performed about influences of CO2 pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency. The findings obtained were applied to the field tests of CO2 pre-pad fracturing and single well puff-n-huff. The results show that the efficiency of CO2 puff-n-huff is affected by micro- and nano-scale effect, kerogen, adsorbed oil and so on, and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil. In the “injection + soaking” stage, the exploitation degree of heavy hydrocarbons is enhanced by CO2 through its effects of solubility-diffusion and mass-transfer. In the “huff” stage, crude oil in large pores is displaced by CO2 to surrounding larger pores or bedding fractures and finally flows to the production well. The injection of CO2 pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure, and the CO2 is liable to filter along the bedding surface, thereby creating a more complex fracture. Increasing the volume of CO2 pre-pad can improve the energizing effect, and enhance the replenishment of formation energy. Moreover, the oil recovery is more enhanced by CO2 huff-n-puff with the lower shale matrix permeability, the lower formation pressure, and the larger heavy hydrocarbon content. The field tests demonstrate a good performance with the pressure maintained well after CO2 pre-pad fracturing, the formation energy replenished effectively after CO2 huff-n-puff in a single well, and the well productivity improved.

Mechanism of inter-well hydraulic fracture interference in the primary horizontal well pattern

Shale reservoirs are characterized by low porosity and low permeability and are difficult to be developed, single horizontal well fracturing has the shortcomings of low modification and insufficient fracture coverage, so multi-well fracturing is often used in the field. Primary horizontal well pattern is one of the main modes for commercialized shale oil and gas extraction, but the interwell interference existing in multi-well fracturing will affect extraction. In this paper, a 3D hydraulic fracturing model was established with the geology‒engineering integration method, and the effects of cluster spacing, fracturing sequence, fracture placement, well spacing, horizontal stress difference and natural fractures (NFs) on hydraulic fracture (HF) propagation and cumulative gas production in multi-well fracturing were investigated. The results are described as follows. Appropriately reducing the cluster spacing to 10 m can effectively reduce interwell fracture hits while obtaining higher initial production; Zipper fracturing has a significant effect on reducing interwell fracture hits. Compared with sequential fracturing, zipper fracturing increases the HF area and cumulative gas production by 4.7% and 4.2% respectively; In order to ensure production while reducing the risk of fracture hits, the well spacing was chosen to be 400m; Compared to symmetric fracture placement, the cumulative production increased by 7.0% and 9.8% for the 1/4 staggered fracture placement and 1/2 staggered fracture placement, respectively; Although more NFs can be communicated and a larger fracture area can be obtained under small stress difference conditions, but the risk of interwell and intercluster fracture hits increases; When the NF inclination is less than 80°, the fracture hits is weakened with increase of NF inclination, when the NF inclination exceeds 80°, the HF tend to pass through the NFs and the fracture hits increases; As the NF density increases, the fracture complexity near the wellbore increases and the fracture hits decreases.

Exploring the influence of external electric fields on the catalytic pyrolysis of oil shale kerogen molecules

Oil shale is a widely distributed and abundant sedimentary rock that can be converted into shale oil through pyrolysis, providing a supplementary solution to the increasing scarcity of conventional fossil energy. However, the traditional pyrolysis process of oil shale faces problems such as low oil yield, high energy consumption, and poor oil quality. Recent experiments have demonstrated that using an external electric field to catalyze the pyrolysis of oil shale can address these problems. However, due to the complex physical and chemical properties of oil shale and its pyrolysis process, the catalytic mechanisms and effects have not been reasonably explained. To address these issues, this study uses density functional theory to calculate the properties of oil shale molecules under external electric fields of different directions and strengths. The results indicate that at electric field strengths far exceeding experimental conditions, the external electric field does have a certain catalytic effect on oil shale, which varies depending on the molecule. However, at electric field strengths achievable in actual laboratory conditions, the catalytic effect of the electric field on oil shale is not significant. Therefore, the mechanisms revealed by past experiments on the catalytic effects of electric fields on oil shale pyrolysis may be partially flawed. This study not only fills the gap in understanding the mechanisms of external electric field catalysis of oil shale but also provides a theoretical foundation for future applications of electric fields in catalyzing oil shale.

Thermo-hydro-mechanical coupling in oil shale: Investigating permeability and heat transfer under high-temperature steam injection

Steam convective heating emerges as a sustainable and effective method for extracting oil shale, where understanding the temperature-dependent evolution of its pyrolytic characteristics, microstructure, and permeability is vital for efficient resource extraction. Through a stress-sensitive micro-CT scanning and a high-temperature and pressure triaxial test apparatus, this research utilizes Balikun oil shale samples to investigate the changes in microstructure and gas production from 20 °C to 550 °C. The study integrates theoretical analysis and numerical simulations to uncover the fundamental connections between internal permeability and heat transfer mechanisms during steam injection. It reveals that oil shale undergoes two critical evolutionary phases: a stability phase below 350 °C, where volatile dispersion occurs, and a rapid increase phase above 350 °C, marked by significant microstructural changes from micro-fractures to extensive through-going fractures due to intense thermal decomposition. This decomposition leads to increased gas production and enhanced thermal fracturing. The threshold temperature is identified at 400 °C, above which the oil shale's mechanical strength and pore pressure increase, leading to decreased volumetric compression until stabilization. These findings demonstrate that higher temperatures enhance fracture connectivity and steam flow, optimizing the heating efficiency in oil shale extraction.

Research on the thermo-hydro-mechanical coupling simulation and deformation spatiotemporal evolution for the entire process of oil shale in-situ mining

The ground surface deformation (GSD) caused by oil shale in-situ mining poses a threat to land resources and human's lives and property. This study, for the first time, conducts a full stratum simulation of the Fuyu oil shale in-situ pyrolysis pilot base, analyzing the evolution characteristics of the temperature field, stress field, and deformation field of the entire stratum profile during the heating and cooling processes of convective heating mining. Considering the changes in the pore structure, thermophysical, and mechanical properties of the stratum, the environmental geological effects of rock deformation during in-situ mining were identified. Simulation results show that after heating, the temperature within 80 cm of the heating well reaches above the initial pyrolysis temperature of 350 °C for oil shale organic matter, and there is a significant stress concentration near the heat source. In the simulation, ground displacement rises in a wave-like manner during heating, quickly subsides after cooling, and finally stabilizes. Eventually, the entire stratum exhibited subsidence, with a subsidence amount of 0.59 cm. The spatiotemporal deformation trend obtained from SBAS-InSAR real-time monitoring results is similar to the simulation results. By comparing the monitoring results with the simulation results, the synergistic deformation mechanism of underground and ground surface co-deformation during in-situ mining of geochemical reactions in the study area was analyzed. The deformation rate is determined by the thermal hysteresis phenomenon and the temperature difference between the heated fluid and the rock layer. This provides scientific support for the geological effect evaluation of oil shale in-situ mining, which helps to improve mining safety and efficiency.

Controls and Geological Significance of Macerals in Hybrid Shales: A Case Study on the Gaoyou Sag, Subei Basin, East China.

In the Gaoyou Sag located within the Subei Basin, the hybrid shales from the second member of the Funing Formation (E1f2) have been identified as a prolific source of shale oil production, despite their characteristically low organic matter content (TOC < 1.5%). This observation suggests that specific macerals within these hybrid shales demonstrate a pronounced hydrocarbon generation potential, thus unveiling a new frontier for shale oil exploration endeavors. In this study, 16 samples were rigorously extracted from both mudstone and hybrid shale strata within the E1f2. An exhaustive suite of organic and inorganic geochemical analyses was conducted on these specimens. The analyses elucidated several key findings: (1) The maceral composition within the hybrid shales is predominantly comprised of alginite, solid bitumen, and inertinite. Remarkably, the variability of alginite content within the hybrid shales is more pronounced than that observed in high-TOC mudstones. High-TOC mudstones are characterized by a preponderance of lamalginite and a paucity of telalginite, leading to a diminished aggregate hydrocarbon potential. (2) Biomarker ratios (e.g., sterane/hopane, C23 tricyclic terpane/αβ C30 hopane, C24 tetracyclic terpane/C26 tricyclic terpane, etc.) suggest a primary derivation from lower aquatic organisms, with a secondary contribution from terrigenous organic matter within the hybrid shales. (3) The accretion of macerals is governed by an intricate set of factors, including the input of terrigenous detritus, paleosalinity, and paleoproductivity. (4) Alginite is identified as the principal constituent responsible for hydrocarbon genesis in hybrid shales. The proliferation of alginite facilitates the concurrent enrichment of shale oil and organic matter within the hybrid shales of the Subei Basin, illustrating a cooperative mechanism underlying the accumulation of shale oil and organic matter. This indicates that even hybrid shales with scant organic content exhibit considerable potential for shale oil exploration.

Insight into adsorption behaviors of shale oil in kerogen slit by molecular dynamics

Shale oil is predominantly stored in organic nanopores, with kerogen playing a pivotal role in its adsorption. This study utilizes molecular dynamics (MD) simulations to quantitatively investigate the adsorption behavior of multi-component shale oil within kerogen slits. Unlike previous studies that focused on single-component hydrocarbon fluids and simplified kerogen models to graphene, this research employs an authentic kerogen structure and a multi-component shale oil model, incorporating the effects of surface roughness. The research analyzes the interaction mechanisms and distribution patterns of light, medium, and heavy components within the pores. Additionally, it examines the effects of temperature, pore size, and wall surface physical and chemical properties on shale oil adsorption. Results indicate that strong adsorption between asphaltene and kerogen significantly reduces the width of the kerogen slits, inhibiting the adsorption of lighter components. The study introduces the concept of effective radius for kerogen slits and provides a quantitative analysis of the adsorption capacity of kerogen surfaces. Different kerogen surface roughness and chemical properties were compared to understand their influence on shale oil adsorption. Key findings show that with increasing temperature, the distribution of hydrocarbons becomes more uniform, with medium components showing the most significant response. Surface roughness of kerogen affects the adsorption capacity, although the component proportions remain consistent, while different chemical property surfaces influence selective adsorption and the overall adsorption amount of shale oil components. This research offers a deeper understanding of shale oil adsorption mechanisms and provides valuable insights for optimizing shale oil extraction and utilization.

CT imaging to study meso-structure evolution of fractured oil shale during in-situ pyrolysis by high-temperature water vapor injection

Preceding the in-situ pyrolysis of oil shale, it is imperative to undertake reservoir fracturing and modification. The intricate evolution of meso-structures in both the fractured fissures and the surrounding rock matrix, constrained by in-situ stress during the pyrolysis process, plays a significant role in influencing the efficiency of heat transfer and the extraction effectiveness of produced materials.This article is based on the Micro-CT scanning technology to study the microscopic structural evolution patterns of high-temperature water vapor in-situ pyrolysis in oil shale with fractured fissures.The main research findings are as follows: Firstly, pre-existing fracturing fissures facilitate the formation and development of vertical bedding fractures.The vertical bedding fractures first appear at 300 °C, with a relative frequency of 1.35%, occurring earlier than the temperature at which such fractures emerge in intact oil shale.Secondly, at 450 °C,there is a pivotal transition point in the evolution of pore-fracture systems, shifting from a predominant increase in length to a predominant increase in aperture.Below 450 °C, changes in pore-fractures are primarily manifested in terms of quantity and length. However, after 450 °C, there is a noticeable increase in the aperture of pore-fracture systems.Thirdly,at temperatures within the range of 300 °C–350 °C, a closure phenomenon occurs in fractures, predominantly involving micro and medium fractures. This closure predominantly affects smaller fractures, providing only a moderate retardation effect on the development of larger fractures. Moreover, in the temperature range of 500 °C–550 °C, there is interconnection observed between large and medium fractures. Pre-existing multiple large fractures are consolidated into a singular interconnected large fracture.Finally, at 450 °C, there is a significant increase in the connectivity of pore-fracture networks. Below 450 °C, the primary connected flow pathways consist of pre-existing fracturing fissures and newly formed parallel bedding fractures. Beyond 450 °C, a complex network of pores takes over as the main interconnected flow channel.

Characterization of oxygen initiation process in the autothermic pyrolysis in-situ conversion of Huadian oil shale

The oxygen initiation process, one of the key processes in the early stage of the autothermic pyrolysis in-situ conversion technology, has not been deeply investigated, which seriously limits its development. In this study, the reaction behaviors, kinetic parameters, heat and product release characteristics during the isothermal oxygen initiation process of Huadian oil shale in O2/N2 mixtures with different oxygen concentrations and initiation temperatures were investigated via TG/DSC-FTIR. The results show that the samples exhibit three different reaction behaviors during the initiation stage, consisting of two main parts, i.e., the oxidative weight-gain and the oxidative reaction phases. The former phase is mainly characterized by the oxygen addition reaction that produces oxidizing groups which increase the sample mass. And the latter stage consists of two main subreactions. The first subreaction involves the oxidative cracking and pyrolysis of oxidizing groups and kerogen to produce fuel deposits such as residual carbon, while the second subreaction focuses on the oxidation of the resulting fuels. Furthermore, increasing the oxygen concentration significantly promotes the above reactions, leading to an increase in the reaction intensity and reaction rate. Owing to the combined effect of oxygen concentration and residual organic matter content, the total heat release increases with the increasing initiation temperature and reaches its maximum at 330–370 °C. In addition, the preheating stage primarily produces hydrocarbon gases, while the initiation stage predominantly generates CO2. As the preheating temperature increases, the CO2 output intensifies, the required reaction time shortens, and the release becomes more concentrated. Based on these findings, a reaction mechanism for the oxygen initiation process of Huadian oil shale was proposed, and recommendations were provided for optimizing the construction process.

Chemofacies characterization of lacustrine shale based on machine learning classification: A case study from the Dongying depression, Bohai bay basin, China

The rapid lithofacies transitions and compositional heterogeneities inherent in lacustrine shale posed significant challenges to accurately characterizing it, thus impeding the optimization of shale oil exploration and extraction. This study employed a multifaceted methodology to address these obstacles, integrating principal component analysis (PCA), K-means clustering, and geochemical trend analysis to precisely identify and characterize nine distinct chemofacies. A comprehensive analysis of petrological characteristics and depositional environments was accomplished by examining core samples, thin sections, scanning electron microscopy (SEM), mineralogical compositions, and total organic carbon (TOC) content. The identification of favorable locations was supported by meticulously considering variables, including TOC, porosity, permeability, and the mineral brittleness index (MBI). This investigation revealed the presence of nine distinct chemofacies within the targeted layer. Specifically, Chemofacies 5, characterized by calcite vein laminations, was identified within Unit 2 parasequence, and Chemofacies 6, enriched with feldspar-quartz mineral laminations, was located within Unit 4 parasequence. Both chemofacies exhibited elevated TOC, enhanced porosity and permeability, and favorable brittleness, qualifying them as ideal sweet spots for shale oil exploration. The insights from this study align with the characteristics of traditionally optimal reservoirs, validate the robustness of the employed methodologies, and carry significant implications for the accurate prediction of terrestrial shale oil sweet spots in future explorations.

Evaluation of SC-CO2–brine on the micro-mechanical properties of lamina shales by micro-scratch test

The mechanism of SC-CO2–brine–rock interaction (SCBRI) and its effect on the mechanical properties of shale are crucial for shale oil development and CO2 sequestration. To clarify the influence of SCBRI on the micromechanics of shale, the lamina and matrix of shale were saturated with SC-CO2–brine for 2, 4, 6, and 8 days, respectively. The micro-scratch technique was then used to measure the localized fracture toughness before and after SC-CO2–brine saturation. Combining the micro-scratch results with SEM-QEMSCAN-EDS analysis, the differences in mineral composition and mechanical properties of lamina (primarily composed of carbonate minerals) and matrix (primarily composed of clay minerals) were studied. The QEMSCAN analysis and micro-scratch results indicate distinct mineralogical compositions and mechanical properties between the lamina and the matrix. The results showed that: (1) SCBRI leads to the decrease in carbonate mineral content and the significant increase in matrix porosity and laminar cracks. In addition, the damage degree increased at saturation for 6 days. (2) SCBRI weakens the mechanical properties of shale. The scratch depth of laminar and matrix increased by 34.38% and 1.02%, and the fracture toughness decreased by 34.38% and 13.11%. It showed a trend of first increasing and then decreasing. (3) SCBRI enhances the plastic deformation behavior of shale, and the plastic index of lamina and matrix increases by 18.75% and 21.58%, respectively. These results are of great significance for evaluating the mechanical properties of shale oil and gas extraction by CO2.

Study on the Applicability of Autothermic Pyrolysis In Situ Conversion Process for Low-Grade Oil Shale: A Case Study of Tongchuan, Ordos Basin, China

The feasibility of the autothermic pyrolysis in situ conversion (ATS) process for low-grade oil shale (OS) has not been determined. In this research, the pyrolysis and combustion properties of Tongchuan OS, with a 4.04% oil yield, were systematically analyzed. The findings revealed that temperatures between 350 and 425 °C favored oil production, while temperatures from 450 to 520 °C resulted in a higher rate of gaseous generation. At 300 °C, the volume expansion and ignition coking caused by the large amount of bitumen generated resulted in severe pore plugging, which significantly increased the combustion activation energy of the residue, while the presence of substantial flammable bitumen also significantly decreased the ignition and combustion temperatures. From 300 to 520 °C, the combustion performance of residue decreases continuously. In addition, pyrolysis residues of Tongchuan exhibited a slightly higher calorific value, between 425 and 520 °C, owing to its higher fixed carbon content (10.79%). Based on the ideal temperature screening method outlined for Tongchuan OS, the recommended preheating temperature for Tongchuan OS was 425 °C, while the optimum temperature for the retorting zone should be 510 °C, considering a heat utilization rate of 40%. These findings contribute valuable insights for the application of the ATS process to low-grade OS.

Study on pyrolysis of ultra-high-quality oil shale: product characterization and a utilization process

ABSTRACT Nantun (NT) oil shale of ultra-high oil yield (>30%) is rare in the world, while the characteristics of this kind of oil shale are not widely reported. An oil shale pyrolysis experiment has been conducted in a tube furnace. The products of gas, oil and char are collected and analyzed on their yield and properties in the range of 450 to 650°C. The oil yield remained above 30% in the range of 450 to 550°C and decreased rapidly from 30.84% to 9.35% at 550 to 650°C. The char yield drops from 66.14% to 57.94% as the pyrolysis temperature increases, and aliphatic hydrocarbon components in char have been cracked completely at 450°C. The yield of pyrolysis gas rises as the pyrolysis temperature increases. CO accounts for the largest proportion of pyrolysis gas, with a volume fraction of over 70%. Based on the characteristics of pyrolysis products, an ultra-high-quality oil shale pyrolysis and utilization process and an Aspen Plus simulation model have been developed that provides estimated material and energy equilibriums for an industrial self-sustaining pyrolysis process to produce char and shale oil. This process can produce 0.61 kg oil and 0.29 kg char per kilogram of oil shale under self-sustaining conditions at 500°C. In practical applications, the pyrolysis temperature is recommended to be 500°C.

Compositional differences of near-critical petroleum from closed pores to wellhead in Gulong shale oil play, Songliao Basin, NE China

The Gulong shale oil play located in northern Songliao Basin is a promising exploration target in China. Member 1 of Qingshankou Formation (Well H) with high thermal maturity was preferred to obtain pressure-retained cores, long-time exposed cores, and produced petroleum (crude oil and gas). The selected samples were subjected to sequential extraction, GC, GC-MS, thermal desorption–gas chromatography (TD-GC) and Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) analysis. The compositional differences of in-situ fluids, residual bitumen trapped in open, confined, and closed pores, as well as wellstream, were systematically investigated. (1) In-situ fluid compositions, with a 30.8% proportion of nC1−5 in n-alkanes, were studied by TD-GC analysis on pressure-retained cores. Interestingly, limited amounts of C8- compounds were detected in long-time exposed bulk cores but were almost absent in exposed powder. Primally poor pore connectivity and partially adsorption or absorption of organic matter contribute to the retention of gaseous hydrocarbons. (2) Sequential extraction is a best method for obtaining compositions of fluid in pores with variable sizes. Aliphatic compounds of residual bitumen trapped in open pores are similar to those in confined pores, while polar compounds are more enriched in confined and closed pores. Originally connected pores in early oil window, has turned into confined or closed pores by compaction and cementation with increasing depth. (3) Wellstream compositions are significantly different from in-situ fluid compositions, especially in shale oil extraction. The proportion of gaseous hydrocarbons in the wellstream (76.2%) is considerably higher than that of in-situ fluids (34.1%). Comparison of aromatic hydrocarbons indicated that the wellstream is sourced from free fluids and partially adsorbed hydrocarbons in open pores. (4) Nitrogen and oxide compounds with a higher degree of condensation (higher DBE value) have poor movability, leading to extremely low content or even absence in crude oil. The compositional differences from in-situ fluids to the wellbore through the stimulated fractures are caused by selective adsorption of pore walls, confinement effect of nanopores and fluid phase changing. This study provides a window to the compositional differences of fluids released from different occurrence spaces and confirms compounds heterogeneity.

A Grand Challenge: Update on Improved Recovery From Tight/Shale Reservoirs

_ This is the third of a series of six articles on SPE’s Grand Challenges in Energy, formulated as the output of a 2023 workshop held by the SPE Research and Development Technical Section in Austin, Texas. Described in a JPT article last year, each of the challenges will be discussed separately in this series: geothermal energy; net-zero operations; improving recovery from tight/shale resources; carbon capture, storage, and utilization; digital transformation; and education and advocacy. _ The exploration and extraction of hydrocarbons from tight or shale formations have revolutionized the global energy landscape, unlocking vast oil and gas reserves previously considered inaccessible. According to estimates, substantial oil production has been reported for various tight plays in the US in 2024 (Fig. 1). However, the production process in tight or shale formations is not without its own set of challenges ranging from technological hurdles to environmental concerns. Therefore, understanding the current outlook is essential for stakeholders to navigate the complex terrain. To address the significant issues outlined by SPE in July 2023 (Halsey et al. 2023), this article intends to explore the complexities of hydrocarbon extraction from tight and shale reservoirs. Description of Tight/Shale Formations First, we present a succinct description of tight or shale formations. Tight or shale oil and gas are hydrocarbons found in oil-bearing mudstone, and shale gas is produced from gas shale or associated with tight oil (Boak and Kleinberg 2020). Tight unconventional formations are characterized by the presence of fine-grained sedimentary rocks that are high in organic matter, such as shale, where hydrocarbons are firmly embedded within the rock matrix. Challenges in Tight or Shale Oil Production The Existence of Complex Geometry. Tight and shale formations are known for their complex geological structures, which can make it difficult to predict the distribution and behavior of hydrocarbons within the reservoir. Additionally, shale formations can exhibit significant variability in their thickness, composition, and the occurrence of natural fractures. Hence, it is crucial to understand and navigate the intricate geology of unconventional shale formations to achieve successful shale oil production (Jiang et al. 2016). Ultralow Reservoir Permeability. The low permeability of tight formations restricts the flow of hydrocarbons, necessitating techniques such as hydraulic fracturing to create artificial pathways for extraction. However, the effective stimulation of fractures requires the use of cutting-edge drilling and extraction methods, such as multistage hydraulic fracturing (fracking) and horizontal drilling, which in turn require precise engineering and a thorough understanding of reservoir characteristics (Pokalai et al. 2015).

Occurrence and mobility of shale oil in the Jiyang Depression, eastern China

The occurrence of shale oil is important for its mobility and holds great significance in determining the available shale oil resources. Here, shale samples from three representative wells with different shale oil production levels in the Jiyang Depression, eastern China, were collected to evaluate the mobility of shale oil from its occurrence. The samples were subjected to Rock-Eval pyrolysis, X-ray diffraction, soluble organic matter, and N2 adsorption measurements. The results indicate that the shales in the high production well have higher contents of clay or felsic minerals, more apolar oil components, and smaller pore sizes than those in the low production well. In particular, the shale oil occurrence exhibits two stages involving pore surface adsorption followed by pore void filling, which are separated by a total organic carbon (TOC) content of 0.6 wt% OC (equivalent to 7.7 mg/gRock, the lower threshold of shale oil content for mobility). The corresponding threshold of pore diameter is 10 nm. By integrating the shale oil occurrence with the oil properties at the producing intervals, the following indices are proposed to evaluate the shale oil mobility and high production level: shale oil content greater than 0.6 wt% OC or 7.7 mg/gRock, oil saturation index greater than 100 mg/gTOC, apolarity index greater than 1, and pore diameter greater than 10 nm. Our work provides an index regime to evaluate the mobility and high production probability of shale oil, which will benefit the exploration and development of shale oil resources.

Numerical analysis of microwave-enhanced oil shale pyrolysis by rotation turntable based on the Arbitrary Lagrangian-Eulerian method

Microwave heating technology has great potential for efficient pyrolysis of oil shale. However, the inhomogeneous heating characteristics of microwave heating can lead to secondary cracking of pyrolysis products, thus reducing the overall oil yield. In order to address this issue, a rotational movement of oil shale under microwave heating has been proposed to obtain a uniform temperature distribution of the oil shale. Then, a new coupled three-dimensional electromagnetic-thermal-chemical-hydraulic model incorporating the Arbitrary Lagrangian-Eulerian (ALE) method was developed to investigate the temperature distribution and pyrolysis characteristics of oil shale under the rotational motion during microwave pyrolysis. The effects of rotational speed, rotational direction, and microwave power on the pyrolysis process of oil shale were explored through this model. The results showed that the introduction of rotational movement effectively addressed the uneven temperature distribution within the oil shale. Compared with the static condition, the rotational condition reduced the secondary reactions of oil products during microwave pyrolysis and increased the oil yield of oil shale to 50.12 %. As the rotation speed increased, the temperature distribution within the oil shale became more uniform, but the total oil yield reached its peak at a moderate speed of 180 s/r. Research on microwave power indicated that rotation increased the maximum usable power and highlighted that reducing the residence time of pyrolysis products within the oil shale was key to increasing oil yield. This study provides a novel approach and numerical simulation method for enhancing the microwave pyrolysis efficiency of oil shale, and the findings of this study are applicable to both the ex-situ and in-situ exploitation of oil shale.

Submodels of 2-d model of the motion of fluid or gas in a porous medium with an external non-stationary source or absorption

The motion of fluid or gas in a porous medium is the main object of investigation of underground hydromechanics. The model describing this motion was called “Porous medium”.In our paper, we study a general 2-d model of the motion of fluid or gas in porous medium with an external non-stationary source or absorption. As the main research method, we use the method of group (symmetry) analysis, which is one of the most effective ways to obtain information about the properties of solutions to differential equations that define a physical model. A group classification of the differential equation defining studied physical model is carried out. As a result, all basic models with different symmetry properties are obtained. For the basic model, which admits the widest group a classification of all its invariant submodels is performed and all invariant submodels, defined by invariant solutions of rank 1 are studied. All solutions found have physical meaning.The set of explicitly found solutions forms a 47-parametric family of exact solutions. Each solution in this family depends on an arbitrary function defining an external non-stationary source or absorption. For each solution, for the specific values of the parameters on which it depends and for this specific function, we obtained a graph of the pressure distribution.Other solutions are used to describe the movement of a liquid or gas if either the pressure and its rate of change, or the pressure and one of its gradient components, are given at an initial time at a fixed point. The set of these solutions depends on 13 parameters and a function defining an external non-stationary source or absorption. For specific values of this function and specific values of the parameters on which each solution depends, the existence and uniqueness of a solution to the corresponding boundary value problem under some additional conditions has been established. Each such problem is solved numerically. The results of these decisions we reflected in the graphs.The significance of obtained solutions lies in the fact that we have obtained a database consisting of two multiparameter families of invariant solutions of rank 1 of the equation describing the motion of fluid or gas in a porous medium in the presence of an external non-stationary source or absorption. Every solution depends on an empirically determined function. These solutions describe specific physical processes. They can also be used as test solutions in numerical calculations related to the study of the motion of fluid or gas in a porous medium during fluids filtering, engineering surveys in the construction of building structures and in the extraction of shale oil or gas.