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Vast reserves are locked up in nonconventional reservoirs. These include gas hydrates, tar sands, tight oil reservoirs, oil shales, shale gas, and coalbed methane. Plastic and solid hydrocarbons are common in sedimentary rocks of diverse ages in many parts of the world. They are distinct from crude oils; many of these hydrocarbons are viscous. The solid and heavy, viscous hydrocarbons occur as lakes or pools on the earth's surface and are disseminated in veins and pores in the subsurface. Two genetically distinct modes of occurrence are recognized: (1) inspissated deposits and (2) secondary deposits. Heavy, viscous oil deposits occur at or near the earth's surface in many parts of the world. The deposits have API (American Petroleum Institute) gravities of 50–150 and typically occur within highly porous sands, generally referred to as tar sands, or bitumen oil sands and heavy oil deposits. Vast reserves are contained within these beds. Two basic approaches have been developed to extract oil from tar sands: surface mining and processing (ex situ) and subsurface extraction (in situ). Two in situ methods to recover oil are cyclic steam injection and steam-assisted gravity drainage. Oil shale, also known as kerogen shale, is a fine-grained sedimentary rock that yields oil on heating. In oil shales, oil is contained within the complex structure of kerogen, from which it may be distilled. Oil shales are widely distributed around the globe and may contain locked within them more energy than in all presently discovered conventional oil reserves. The world's oil shales may contain 30 trillion barrels of oil. Extraction methods include surface mining and retorting and subsurface heating and extraction. The oil shale extraction industry has seen several “boom and bust” cycles. The reasons for the rise and fall of the oil shale extraction industry are twofold: economics and technology. Tight oil reserves consist of sapropelic organic-rich source beds and adjacent tight (low porosity and permeability) reservoirs and are located in the oil generation window in a sedimentary basin. Keys to production include the following: abnormal pressure; matrix and fracture porosity and permeability; low matrix water saturation (some oil wet systems); organic-rich, mature source rocks; brittle reservoir rocks; and pervasive oil saturation. The most successful low-permeability oil play to date is the Bakken Formation of the Williston Basin. Coalbed gas is now commercially produced from Pennsylvanian coal measures in Alabama, Cretaceous coals from the western interior basin of the United States. Most coals produce dry gas, methane rich. Coal acts as both a source rock and a reservoir rock for gas. Gas is retained in coalbeds as sorbed gas and free gas in fractures (or cleats). Most coalbed gas deposits go through a dewatering stage before significant gas production occurs. Shale gas production in the United States first occurred in 1821. Shale gas exploration and production has undergone a renaissance in the United States in the last 20 years. The revolution has been brought about by a combination of horizontal drilling, multistage hydraulic fracturing, and three-dimensional seismic surveys. Shale gas reservoirs are self-sourced. The shales are organic-rich, fine-grained sedimentary rocks. The shales may be thermally immature to postmature and contain biogenic or thermogenic gas. Gas is stored in shales as sorbed gas, free gas in fractures and intergranular porosity, and dissolved in bitumen or kerogen. Tight gas reservoirs (usually sandstones) can be subdivided into two types based on porosity and low permeability. These two types are referred to as high porosity (HP) reservoirs and low porosity (LP) reservoirs. The HP type is present in the northern Great Plains and eastern Plains region of the United States. The reservoirs are at shallow burial depths and consist of chalks, siltstones, and very fine-grained sandstones. Although these reservoirs have HP (10–40%), they have low in situ permeability (

The work summarizes the various process emissions that occur during petroleum refining. There are also general descriptions of the various pollution, health, and environmental problems especially specific to the petroleum industry and places in perspective the government regulations as well as industry efforts to adhere to these regulations. The objective is to indicate the types of emissions and the laws that regulate these emissions.

The Mississippian Barnett Shale within the Bend arch–Fort Worth Basin is a major continuous shale-gas resource in the United States. The Barnett Shale was last assessed by the US Geological Survey (USGS) in 2003 and only included vertical drilling. The Barnett Shale was reassessed in 2015 for undiscovered, technically recoverable gas and oil resources to include the impact of over 12 yr of horizontal-drilling development. The 2015 USGS assessment delineated three continuous assessment units (AUs): (1) Barnett Continuous Gas AU, (2) Barnett Mixed Continuous Gas and Oil AU, and (3) Western Barnett Continuous Oil AU. The AU boundaries were defined by hydrogen index (HI) values as a proxy for thermal maturity, in addition to shale thickness. An HI value of 100 mg hydrocarbon (HC)/g total organic carbon (TOC) was used to define the Barnett Continuous Gas AU boundary. The Barnett Mixed Continuous Gas and Oil AU was defined within the northeastern part of the basin where HI values are greater than 100 mg HC/g TOC and the shale thickness exceeds 100 ft (31 m). Resulting undiscovered, technically recoverable resource estimates for these two AUs were 53 tcf of gas, 172 million bbl of oil, and 176 million bbl of natural gas liquids. The western part of the Barnett Shale (HI >100) comprises the Western Barnett Continuous Oil AU, and it was not quantitatively assessed. The recent USGS assessment is nearly double the 2003 mean resource estimate of 26.2 tcf of gas and is the first study to provide quantitative estimates for shale-oil resources in the Barnett Shale.

Although well logs and core data show that there is significant oil content in Bakken shales, the oil transport behavior in these source rocks is still not well understood. This lack of understanding impedes the drilling and production operations in the shale members. A series of experiments were conducted to investigate the rock properties of the Bakken shales and how to extract oil from the shales using supercritical CO 2 . High-pressure mercury injection tests showed that pore throat radii are less than 10 nm for most pores in both the upper and lower Bakken samples. Such small pore sizes yield high capillary pressure in the rock and make fluid flow difficult. Total organic carbon content was measured using 180 shale samples, and kerogen was characterized by Rock-Eval pyrolysis, which indicated considerable organic carbon present (10–15 wt%) in the shales. However, oil and gas are difficult to mobilize from organic matter using conventional methods. A systematic experimental procedure was carried out to reveal the potential for extracting hydrocarbons from the shale samples using supercritical CO 2 under typical Bakken reservoir conditions (e.g., 34.5 MPa and 110 °C). Results showed that supercritical CO 2 enables extraction of a considerable portion (15–65%) of hydrocarbons from the Bakken shales within 24 h. Measurement of CO 2 adsorption isotherm showed that Bakken shale has a considerable capability to trap CO 2 (up to 17 mg/g) under a wide range of pressures. The experimental results suggest the possibility of using supercritical CO 2 injection to increase the ultimate oil recovery and store a considerable quantity of CO 2 in the Bakken Formation.

Four oil shale samples with different amounts of organic and mineral matter were analysed through non-isothermal thermogravimetric analysis using a heating rate of 50 °C min−1 in nitrogen. The goal of the paper is to study the supposed catalytic effect of the indigenous and removed minerals. The samples contained 30, 49, 70 and 90% of organic matter, respectively. X-ray diffraction analysis was used to identify the minerals in the samples. Thermal analysis experiments were carried out up to temperatures of 850 °C in pyrolysis conditions. The mass loss data were used to study the variations in the conversion profiles of the organic matter depending on the content of the mineral matter. The obtained data and the comparison of the sample composition show that the effect of the mineral matter amount on the course of the pyrolysis processes is insignificant.

Summary Production of tight oil from shale reservoirs in North America reduces oil imports and has better economics than natural gas. Currently, there is a strong interest in oil production from Bakken, Eagle Ford, Niobrara, and other tight formations. However, oil-recovery fraction for Bakken remains low, which is approximately 4–6% of the oil in place. Even with this low oil-recovery fraction, a recent United States Geological Survey study stated that the Bakken and Three Forks recoverable reserves are estimated to be 7.4 billion bbl; thus, a large volume of oil will remain unrecovered, which was the motivation to investigate the feasibility of enhanced oil recovery (EOR) in liquid-rich shale reservoirs such as Bakken. In this paper, we will present both laboratory and numerical modeling of EOR in Bakken cores by use of carbon dioxide (CO2), methane/ethane-solvent mixture (C1/C2), and nitrogen (N2). The laboratory experiments were conducted at the Energy and Environmental Research Center (EERC). The experiments recovered 90+% oil from several Middle Bakken cores and nearly 40% from Lower Bakken cores. To decipher the oil-recovery mechanisms in the experiments, a numerical compositional model was constructed to match laboratory-oil-recovery results. We concluded that solvent injection mobilizes matrix oil by miscible mixing and solvent extraction in a narrow region near the fracture/matrix interface, thus promoting countercurrent flow of oil from the matrix instead of oil displacement through the matrix. Specifically, compositional-modeling results indicate that the main oil-recovery mechanism is miscible oil extraction at the matrix/fracture interface region. However, the controlling factors include repressurization, oil swelling, viscosity and interfacial-tension (IFT) reduction, diffusion/advection mass transfer, and wettability alteration. We scaled up laboratory results to field applications by means of a compositional numerical model. For field applications, we resorted to the huff ’n’ puff protocol to assess the EOR potential for a North Dakota Middle Bakken well. We concluded that long soak times yield only a small amount of additional oil compared with short soak times, and reinjecting wet gas, composed of C1, C2, C3, and C4+, produces nearly as much oil as CO2 injection.

The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K2qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K2qn1), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (Tmax) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K2qn1 shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K2qn1 shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin.

The international daily increase in energy demands requires exploration of new and unconventional energy resources. Unconventional oil and gas have received special attention in recent years as an important source of fossil fuel. This is true especially in North America; United States and Canada, and in other regions in the world including the Middle East. The technological advancements have made the production from unconventional resources possible and more economical. The learning curve and a substantial experience are being developed in North America, where most of the shale developments took place. This paper presents an effort to summarize the current experience on shales of North America from different aspects: rock mechanics, rock/fluids interaction, gas flow mechanisms through shale rocks, proppant embedment and water recovery after shale fracturing. Shale rocks are composed of rock matrix, kerogen, and natural fractures. The mineralogy of shale rocks changes from one field to another. This change in mineralogy will impact the mechanical properties of the shale reservoirs. For example, Haynesville shale becomes more ductile with the increase in its clay content. Similar trends were seen for Lower Bakken shale, while other shale reservoirs, like Eagle Ford, Barnett and Middle Bakken contain more quartz and calcite, which make the rocks harder and easier to fracture. The rock mechanical properties of shale rocks can change as a direct result of the exposure of these clay-sensitive rocks to fracturing fluids. This has been confirmed in literature where Middle Bakken shale lost 52% of its Young's modulus after exposure to slickwater at 300 °F for 48 h. Porosity in unconventional reservoirs can be found in both organic and inorganic parts of the rock. The porosity of the organic matter, and hence the amount of gas stored in kerogen, cannot be neglected and should be considered in the calculation of the gas originally in place. Porosity in organic matter depends on several parameters; among the most important ones is the maturity of the shale itself. Flow of gas in shale rocks is governed mainly by the non-Darcy effects. In addition, gas can be stored and produced from different sources including natural fractures, organic matter and inorganic matrix. Porosity and permeability in organic matter cannot be neglected and it is very important when it comes to storage and flow in shale reservoirs. As a direct result of using different fluid systems in hydraulic fracturing of shale reservoir, an impact on the rock mechanical properties of the rocks were noticed and recorded. This impact can be significant based on several parameters like the temperature, time to exposure and the mineralogy of the shale rock itself. The rock properties can change in a way the rock becomes more ductile and that can increase the proppant embedment in the rock and the overall fracture conductivity to decrease. Among the different fracturing fluid systems used in the field, the use of slickwater in hydraulic fracturing represents a major challenge as a huge volume of water is used in such treatment. In Marcellus shale formation, hydraulic fracturing of one well may require an average volume of 3–8 million gallons of water. Recycling of produced water has been attempted in North America in Marcellus shale play, where re-use of the flowback water resulted in 25% reduction in the fresh water volumes and it reduced the cost of disposing produced water by 45%–55%. A comprehensive understanding and analysis on unconventional reservoirs is required for the Middle Eastern reservoirs. The paper presents a summary of all of these findings from North America.

ConspectusOver the past decade, the United States has become a world leader in natural gas production, thanks in part to a large-fold increase in recovery from unconventional resources, i.e., shale rock and tight oil reservoirs. In an attempt to help mitigate climate change, these depleted formations are being considered for their long-term CO2 storage potential. Because of the variability in mineral and structural composition from one formation to the next (even within the same region), it is imperative to understand the adsorption behavior of CH4 and CO2 in the context of specific conditions and pore surface chemistry, i.e., relative total organic content (TOC), clay, and surface functionality.This study examines two Eagle Ford shale samples, both recovered from shale that was extracted at depths of approximately 3800 m and having low clay content (i.e., less than 5%) and similar mineral compositions but distinct TOCs (i.e., 2% and 5%, respectively). Experimentally validated models of kerogen were used ...

Based on the understandings on enrichment rules of marine shale gas in southern China and data obtained from exploration and development in Fuling shale gas field, this article discusses the key controlling factors on shale gas enrichment and their relationships, it also discusses further the theory of Two-Factor Enrichment of marine shale gas in southern China. The bases for shale gas enrichment are shale gas generation and accumulation, the shale gas reservoirs of deep-water shelf are characterized by high TOC, high porosity, high gas contents and high siliceous contents, with high hydrocarbon-generation intensity. The organic pores are rich in shales in favorable for stimulation, so they are the bases for large scale hydrocarbon accumulation. Preservation conditions are vital to the formation and enrichment of shale gas reservoirs, good top and base layers can effectively prevent hydrocarbon from escaping vertically at the beginning of hydrocarbon generation. Shale gas preservation conditions depend on the intensity and duration of tectonic movements, good preservation conditions are key geological factors for shale gas accumulation, shale reservoirs have high gas contents, high porosity and high pressure and are likely to form high yield area of shale gas. Key words: Sichuan Basin, Fuling shale gas field, Lower Silurian, Longmaxi Formation, shale gas, enrichment and high production, controlling factors

As an important unconventional resource, oil shale has received widespread attention. The oil shale of the Chang 7 oil layer from Triassic Yanchang Formation in Ordos Basin represents the typical lacustrine oil shale in China. Based on analyzing trace elements and oil yield from boreholes samples, characteristics and paleo-sedimentary environments of oil shale and relationship between paleo-sedimentary environment and oil yield were studied. With favorable quality, oil yield of oil shale varies from 1.4% to 9.1%. Geochemical data indicate that the paleo-redox condition of oil shale’s reducing condition from analyses of V/Cr, V/(V + Ni), U/Th, δU, and authigenic uranium. Equivalent Boron, Sp, and Sr/Ba illustrate that paleosalinity of oil shale is dominated by fresh water. The paleoclimate of oil shale is warm and humid by calculating the chemical index of alteration and Sr/Cu. Fe/Ti and (Fe + Mn)/Ti all explain that there were hot water activities during the sedimentary period of oil shale. In terms of Zr/Rb, paleohydrodynamics of oil shale is weak. By means of Co abundance and U/Th, paleo-water-depth of oil shale is from 17.30 to 157.26 m, reflecting sedimentary environment which is mainly in semi deep–deep lake facies. Correlation analyses between oil yield and six paleoenvironmental factors show that the oil yield of oil shale is mainly controlled by paleo-redox conditions, paleoclimate, hot water activities, and depth of water. Paleosalinity and paleohydrodynamics have an inconspicuous influence on oil yield.

Shale to liquid (STL) and syngas to liquid (GTL) fuel techniques are applied to vast discovered resources of oil shale to fulfil current and future liquid fuel demands. To utilize the different constituents of oil shale efficiently, cases 1 and 2 were designed to produce liquid fuels and hydrogen as end products. In case 1, which produces shale oil and retorting gas from oil shale that are further processed by shale oil hydrogenation and retorting gas steam reforming to produce liquid fuels and hydrogen, respectively. For comparison, case 2, including oil-shale retorting, retorting gas steam reforming, shale oil hydrogenation, and Fischer–Tropsch synthesis technology, was also established. Cases 1 and 2 are compared (with respect to end products and energy efficiencies) with each other by modeling and simulating three scenarios for case 1 and four scenarios for case 2. The simulation results show that the third scenario of case 1 and the fourth scenario of case 2 provide the most important required end products, namely, hydrogen and hydrocarbon fuels. The overall production of hydrocarbon fuels in the fourth scenario of case 2 increases 0.95 wt % more than that of the third scenario of case 1, whereas the production of hydrogen reduces by 14.7 wt % and the external energy consumption is 20 % higher in the fourth scenario of case 2, relative to that of the third scenario of case 1. For the third scenario of case 1 and fourth scenario of case 2, the total energy efficiency of the system is 43.45 % (high heating value (HHV)) and 43.16 % (HHV), respectively. The whole system is modeled and simulated in the Aspen Plus V8.4 program and the results are compatible with those of industrial and experimental data. Sensitivity analyses are performed to show the effects of various key operating parameters on the production yield of shale oil, retorting gas, and hydrogen.

Significant amount of different maturity kerogen in Bazhenov oil-shale formation are reserves of hydrocarbons to be recovered by enhanced oil recovery methods in nearest future when the conventional oil field development drops crucially. A technology of in-situ kerogen conversion into synthetic oil in Bazhenov formation opens broad perspectives in development of Bazhenov formation, West Siberia, Russia. Laboratory investigation of in-situ kerogen conversion process in the presence of supercritical water performed on Bazhenov formation rocks is presented in this study. A feasibility of the tertiary hydrous pyrolysis hydrocarbons (HC) recovery method was accessed. Study helped to obtain reliable data to validate the numerical simulation model for that enhanced oil recovery method. First tests of hydrous pyrolysis extraction were conducted on crushed oil shale samples at temperatures of 300, 350, 400 and 480 °C and under formation pressure of 30 MPa. Liquid HC extraction from sample started from 400 °C. The secondary hydrocarbons conversion process was detected at reaction temperature of 480 °C. Second stage of laboratory tests allowed to find optimal parameters for in-situ kerogen conversion – optimal conversion temperature, time of the conversion. The experiments on Bazhenov formation cores with low kerogen maturity were conducted in closed vessel at formation pressure and in temperature range of 250–400 °С. It was found that oil synthesis starts at 300 °С. Amount of liquid products increased at temperatures above 350 °С, but the secondary cracking processes had been observed also. It was discovered that hydrous pyrolysis and cracking caused an increase in rock porosity and permeability. Results obtained in this study were used in numerical simulation.

Shale hydrocarbon has recently received widespread interest due to its emergence as a type of clean energy. However, calculating the quantity of lacustrine shale hydrocarbon is a challenging issue that the petroleum geologists are currently facing, which results in a poor understanding of shale-hydrocarbon distribution. Using mass conservation law, as well as geochemical and geological rules, this paper tries to establish mathematical models for calculating the quantities of lacustrine shale hydrocarbon. A simple method is also introduced to acquire the target values. The lacustrine shale of the Yanchang Formation in the Ordos Basin is selected to establish the mathematical models and the parameter systems. The method is tested to be computationally efficient and highly practical. The results show that the generated shale gas and shale oil per ton of lacustrine shale of the Yanchang Formation are 1.2 m3 and 0.75 kg, respectively. The lacustrine shale of the Yanchang Formation has a high hydrocarbo...

The Yanchang Formation in the Ordos Basin in North Central China represents a large, long-lived lacustrine system of the late Triassic Period. The extensive shales within this system provide hydrocarbons (HCs) for conventional and unconventional oil and gas reservoirs. In the formation, the Chang 7 shale is the thickest shale with the best geochemical parameters, and it is the main source rock in this area. In recent years, the discovery of shale gas in the Chang 7 shale has promoted the exploration and development of lacustrine shale gas in China. We have estimated the shale gas resource potential based on the analysis of the geologic conditions of the Chang 7 shale. The average thickness of the Chang 7 shale reaches 42.6 m, and the main organic matter types are types [Formula: see text] and [Formula: see text]. The average content of organic carbon is more than 3%, and the average HC potential is [Formula: see text]. However, the thermal maturity of the Chang 7 shale is low with a vitrinite reflectance [Formula: see text] ranging from 0.83% to 1.10%. The Chang 7 shale lithology consists of shale and sandy laminations or thin sandstones. The shale is characterized by high clay mineral content and poor porosity and permeability, with an average porosity of 1.8% and an average permeability of [Formula: see text]. The sandy laminations or thin sandstones are characterized by relatively higher brittle mineral content, relatively lower clay mineral content, and higher porosity and permeability. The pores of the Chang 7 shale include primary intergranular and intragranular pores, secondary intragranular and intragranular dissolved pores, fracture pores, and organic-matter-hosted pores. The proportion of adsorbed gas, free gas, and dissolved gas is approximately 52%, 37%, and 11%, respectively, and the shale gas resources of the Chang 7 shale are [Formula: see text].

The Chang 7 Member shale gas of the Upper Triassic Yanchang Formation, Ordos Basin, is a representative of continental shale gas in China. The Chang 7 shale is currently in the oil window, suggesti...

This study was performed in order to evaluate shale oil in the first member of the Qingshankou formation (K2qn1) in the Songliao basin in northeastern China. The evaluation was carried out using immature type I kerogen kinetics in a closed system, two wells drilled into oil prone source rocks, in order to apply Rock-Eval, mineral composition and residual hydrocarbon analysis, and the hydrocarbon sorption method. The “oil windows” for K2qn1 in mudstone and shale wells range from 0.6% to 1.05%, with maximum hydrocarbon generation at around 420 mg of hydrocarbon per gram of total organic carbon. In addition, the brittle mineral contents of K2qn1 conform to the requirements for industrial oilfield development and exploitation. Our results demonstrate that there is clear potential for shale oil exploration in the K2qn1; a highly potential zone is defined as low risk at burial depths of greater than 2065 m for well H14, while well X83 exhibits relatively discrete depth based on oil saturation and production ind...

Oil shale is a sedimentary rock that contains organic complexes of kerogen throughout its mineral matrix. Kerogen can be converted into hydrocarbons through various chemical processes, such as pyrolysis, which is used by Petrobras for oil production in Brazil. To process oil shale, the shale is placed into a vertical cylindrical reactor and subjected to a gas stream that induces pyrolysis at a temperature of 500 °C. The purpose of this study was to examine possible inorganic and petrofabric transformations in oil shales as a result of the pyrolysis process. Samples of oil shale and retorted material (residue from pyrolysis) were analyzed to compare possible chemical, mineralogical and petrofabric variation between the two materials. X-ray fluorescence (XRF), X-ray diffraction (XRD), petrographic analysis and X-ray computed microtomography (μCT) were used for this purpose. Additionally, the effects of temperature and heating rate on the thermal degradation of the samples were determined using thermogravimetric analysis combined with differential thermal analysis (TGA/DTA). The samples of retorted material were obtained with a pyrolysis simulator called BSTU. The chemical and mineralogical results for the oil shale and retorted material showed that the pyrolysis process did not cause significant changes in the rock. The chemical analysis showed that the chemical composition was dominated by SiO2 and Al2O3, while the mineralogical analysis detected mainly quartz, feldspar and clay minerals, as well as pyrite. The thermogravimetric curves showed that organic matter and pyrite decomposed between 400 °C and 550 °C. The main changes occurred in the petrofabric, as the pyrolysis process caused intense fracturing parallel to the original bedding structure of the shale. The process was more pronounced in shales with higher levels of organic matter and led to pore expansion and higher pore connectivity, thus allowing the escape of fluids and gases.

The paper presents approaches to characterization of shale source rocks using geochemical data for the case of the Bazhenov petroleum system in West Siberia. Regional patterns of oil distribution in the Bazhenov shale are shown to depend on their original total organic carbon (TOC) content and thermal maturity. The existing thermal maturity model for the Bazhenov Formation based on vitrinite reflectance (Rvto) of nearby beds has been updated using parameters measured by Rock-Eval pyrolysis (Tmax, HI, PC, and RC) for the shale itself. The results were used to quantify hydrocarbon resources in different maturity zones. The relationship between TOC and the presence of para-autochthonous oil found for logged zones in the Bazhenov section allows allocating and quantifying oil resources in unlogged beds.

Oil shale pyrolysis by solid heat carrier in moving bed with internals (MBI) was investigated with the aim to identify the effect of oil shale properties (moisture content and particle size) and heat carrier types on the physicochemical properties and distributions of pyrolysis products. Pyrolysis of oil shale with high moisture content of 10 wt% caused obvious increase in shale oil yield due to the protective effect of steam atmosphere by its reducing secondary reactions and also catalysis action of shale ash. The obtained highest shale oil yield was close to the yield of Fischer Assay. Pyrolyzing dried oil shale produced shale oil containing more light oils (gasoline and diesel) and allowed higher gas yield. Pyrolysis of large size (i.e. > 10 mm) oil shale reduced oil yield but increased light oil content due to the required long time for heat transfer and intra-particle volatile diffusion. Comparing with ceramic balls, shale ash as the heat carrier presented a favorably catalytic effect on cracking and upgrading of shale oil. With increasing pyrolysis temperature from 465 to 525 °C, using shale ash greatly raised light oil content by 10.24% (relatively), considerably reduced the content of heteroatomic compounds, and promoted the conversion of aliphatics to aromatics. Shale ash carrier particles enabled better dust removal than ceramic balls did to attain oil product with a dust content below 0.2 wt%. Generally, oil shale pyrolysis using shale ash heat carrier in MBI process has obvious effects of in-situ shale oil upgrading and in-bed dust removal to allow good pyrolysis performance.

Qualitative and quantitative evaluations of resource potential are of significant importance for both exploration and exploitation of shale oil. We investigate the shale oil resource potential in E2s4L (the lower submember of the fourth member of the Paleogene Shahejie Formation) of Damintun Sag by both qualitative and quantitative methods. From the viewpoint of qualitative evaluation, it is reasonable to hope that the target shale, with adequate oil-prone organic matter (OM) in the peak and late oil generation stage, forms a shale oil reservoir. The total oil content in shale is evaluated from free hydrocarbons in shale (S1) by correcting the heavy and light hydrocarbons and the resins and asphaltenes. The total oil content is found to be over 4.45 times greater than the original S1. The evaluation threshold of high-abundance oil is determined by both the total oil content (ST) and the ratio of ST to the total organic carbon content with values that are greater than 8 mg/g and 1, respectively. Based on t...

Shale gas exploration in the Qinghai–Tibet area has lagged behind as compared to the other regions of China, and no shale gas reservoir has been discovered till yet. The analysis of the geological and reservoir characteristics of the Biluocuo oil shale samples from the southern Qiangtang Basin indicates the following findings. The oil shale has a high organic matter content, and the average mass fraction of organic carbon is 4.62%. Additionally, the organic matter is type II. The thermal evolution of organic matter has reached from a low to a high mature stage, and the porosity and permeability are 1.25% and 0.0102 mD, respectively. The rocks are highly brittle, and the primary mineral components are calcite and quartz, whose average contents are 58% and 22%, respectively. Moreover, the rock has a high adsorption capacity. Furthermore, a comparison with the five major shale gas systems in North America found the following. The Biluocuo oil shale is similar to the Barnett shale and Ohio shale, part...

The depletion of conventional energy sources is leading to increased demand for unconventional energy sources. Shale gas is an important unconventional energy source that has been successfully developed and utilized in the United States. CO2 enhanced shale gas recovery (CO2-ESG) is a promising shale gas extraction technology. Supercritical CO2 injection can enhance the shale gas recovery through competitive absorption between the methane and the CO2 while also providing CO2 geological sequestration. However, assessments of the feasibility of CO2 enhanced shale gas recovery in field scale trials is quite complicated given the complex pore structures in shale reservoirs and the ultralow permeability. This paper describes a triple porosity, dual permeability (TP-DK) model that includes the effects of the shale gas adsorption and desorption, the competitive adsorption and binary gas diffusion. The Sichuan basin in China is selected as the target reservoir. The key parameters in this simulation were determined by experimental measurements of shale samples from the Lower Silurian Longmaxi Formation (LSLF) shale in the Sichuan basin. The results show that the CO2 injection can significantly enhance the shale gas recovery. A 90 m thick shale gas reservoir with a 1200 m horizontal well absorb injections of CO2 captured from a large 1000 MWe coal-fired power plant for 2 years. However, the volume flow rate of the CO2 sequestration decreased with time as the production pressure decreased. Both the production time and the production pressure should be considered on the synergy between the CO2 sequestration and the shale gas recovery.

Shale oil exploration of the Permian Lucaogou Formation (P2l) has greatly advanced in the Jimusar Sag in the Junggar Basin. However, despite the strong exploration prospects of shale oil resources, the potential of shale oil resources in the Junggar Basin has been insufficiently assessed. This study performs systematical evaluation of P2l source rocks in the Jimusar Sag and proposes an improved hydrocarbon generation potential method to assess the hydrocarbon generation and expulsion characteristics and evaluates the shale oil resource potential of the P2l source rocks in the Jimusar Sag. The results show that the P2l source rocks are thick (up to 200 m) and are distributed over a wide area (up to 1200 km2) in the study region. It contains high TOC (2%–5%), characterized by dominantly type I and type II kerogen. The source rocks are in the low mature–mature stage, and possess good conditions for generation of hydrocarbons. The P2l source rocks reached the hydrocarbon expulsion threshold at a thermal maturity of 0.8% vitrinite reflectance. The efficiency of hydrocarbon expulsion of the source rock is 34%. The amounts of hydrocarbons generated and expelled were 65 × 108 t. Based on the above information, the shale oil resources potential is calculated to be 43 × 108 t, indicating very good shale oil resource prospect in the P2l source rocks of the Jimusar Sag. Copyright © 2017 John Wiley & Sons, Ltd.

The sorptional properties of fuel shales and spent shales in removing organic compounds (petroleum and its derivatives) from water are studied. The basic benefit of spent shale as a sorbent is that it is available at no expense as the processing waste of fuel shale. After sorption, the fuel shale or spent shale saturated with petroleum or its derivatives may expediently be used as a fuel, on account of their high calorific value.

The source rock quality, organic pore structure, occurrence state and sealing mechanisms of shale gas in the Ordovician Wufeng – SilurianLongmaxi Formation (O3w-S1l), Fuling region, Sichuan Basin were studied using a series of techniques including ultra-microscopic organic maceral identification, FIB-SEM, high temperature/pressure isothermal adsorption and isotopic age dating of noble gas. The results show that: (1) O3w-S1l organic-rich shale was mainly formed in a sedimentary environment with high productivity in surface water and hypoxia in bottom water, which can be divided into two sections according to TOC. The lower section (TOC≥3%) is mainly composed of graptolite, phytoplankton, acritarch, bacteria and solid bitumen. Graptolite is the main contributor to TOC, but the shale gas is mainly derived from hydrogen-rich organic matter such as phytoplankton, acritarch and pyrolysis of liquid hydrocarbons produced by hydrogen-rich organic matter. (2) Organic pores, as principal reservoir space for shale gas, exist in hydrogen-rich organic matter and solid bitumen. The graptolites and plenty of other organic matter stacking distribution in lamina provide both reservoir space for supplement and effective pathways of connected pores for shale gas. (3) Shale gas in Fuling region is in supercritical state and dominated by free gas. The match of formation time of closed shale gas system and gas-generation peak, as well as slight alteration degree of sealing conditions in the later stage, are key factors controlling the retention and accumulation of shale gas in the regions with high thermal maturity and complex tectonic background. Adsorption, capillary sealing and slow diffusion of shale are the main microscopic mechanisms for the retention and accumulation of shale gas. It thus can be seen that the generation and accumulation of marine shale gas with high thermal maturity in complex structure areas is controlled jointly by anoxic depositional environment, excellent hydrocarbon rock quality, superior reservoir space and favorable sealing conditions. Key words: Sichuan Basin, Fuling gas field, shale gas, hydrocarbon-forming organisms, reservoir space, occurrence state, sealing mechanism

The influence of shale ash on the pyrolysis of Huadian oil shale was investigated. It was found that under the catalysis of shale ash, aliphatics in shale oil were partially converted to aromatics, and the long- chain aliphatics were converted to shorter ones. This effect could be improved by increased content of shale ash or by augmented temperature. Beyond the Diels-Alder reaction for the formation of aromatics, a novel reaction route of cyclization of aliphatics followed by dehydrogenation to aromatics was proposed. The component of CaO in shale ash plays an important role to the general performance of shale ash.

In situ retorting and extraction methods for oil shale and heavy oil formations require large amounts of heat. Oil shale formations require heat to convert kerogen into oil, and heavy oil formations require heat to lower oil viscosity. We present a method by which the amount of heat required to raise the temperature of a hydrocarbon- and water-saturated rock formation is calculated from downhole geochemical data typically provided by a nuclear spectroscopy log. The heat capacity of various inorganic minerals, organic materials, and water, along with enthalpies from water evaporation, mineral decompositions, and pyrolysis, are used in the calculation. The heat requirements, expressed in units of kilojoule per kilogram, estimated from downhole geochemical data are found to agree with those calculated from laboratory-determined mineralogy within 1% at 300 °C for most formations. Mineral composition sensitivity and error propagation were investigated. These results suggest that heat requirements for oil shale...

Shale oil refers to liquid hydrocarbons existing in free, dissolved or adsorbed states in the effective source rock of mudstones or shales, where some residual oil is retained after hydrocarbon generation and expulsion from the mudstones or shales. Basically shale oil experiences no migration or only undergoes some primary, short-distance migration within the source rocks. So far, there is no consensus on the exact definition of shale oil in China. Researches on the reservoir-controlling factors and evaluation elements are also far from sufficient. In this study, shale oil reservoirs are defined as mudstones or shales excluding the interbedded or adjacent layers of coarser siliciclastic or chemical-biogenic lithofacies (e.g. siltstone, carbonate, salt or chert layers) in the source rocks. According to different reservoiring mechanisms, shale oil reservoirs are classified into “fracture type” and “matrix type”. The general features of shale oil reservoirs include: rich in organic matters, dominated by Type I and II1 kerogen (with Ro = 0.6%-1.2% and total organic content (TOC) > 2.0%), complex mineral compositions and laminated structures, tight storage space, low porosity and ultra-low permeability, and as well as the requirement for reservoir fracturing. This paper emphasizes the critical role of organic matter in the formation and evaluation of shale oil reservoirs, and its critical control on the oil generation potential and storage capacity of shale, which eventually determine the oil content and productivity of shale oil reservoirs. Besides, a set of reservoir evaluation criteria is also put forward with a focus on the TOC content, in which the threshold values of TOC are set to be 2% and 4%, and a variety of indicators are taken into account including the type and maturity of organic matter, the thickness of organic-rich shale, mineral compositions and rock types, porosity and permeability, and fracturing ability. The evaluation criteria divide shale oil reservoirs into three grades, i.e., target reservoir, favorable reservoir and invalid reservoir. Key words: shale oil, tight oil, reservoir characteristics, evaluation elements and criteria, organic matter content

The rising worldwide energy demand has greatly stimulated the exploitation of shale gas. Meantime, global warming mainly caused by CO 2 emission is a significant concern. As a new scenario, injecting CO 2 to displace shale gas is proposed to improve the exploitation efficiency of shale gas and reduce the amount of CO 2 emission. In this work, we use a grand canonical Monte Carlo simulation to investigate the displacement of shale gas by CO 2 and the sequestration of CO 2 simultaneously in a modeled shale matrix at different geological depths from 1 to 4 km, where the shale is modeled by inorganic clay mineral and organic matter. We find that both the displacement amount of CH 4 and the sequestration amount of CO 2 increase with the pore size of the shale at a fixed CO 2 injection pressure, which suggests that the hydro-fracturing technology would be very beneficial for displacement exploitation of shale gas. Moreover, we also find that the optimum operating condition for CO 2 displacing shale gas is at the depth of 1 km, which provides a guidance and reference for displacement exploitation of shale gas by CO 2 .

The thermolysis of shale (regular shale from the Kenderlyk field in Kazakhstan) with the recirculation of high-boiling shale-oil fractions (above 340°C) in a system with a solid heat source is investigated by balance analysis. Such recirculation boosts the quality of the shale oil obtained. It is characterized by lower density, lower sulfur content, and higher yield of the light fractions employed in automobile fuels (gasoline and diesel fuel).

Compared with the petrochemical industry, oil shale refinery industry is still relatively backward and has many shortcomings, such as poor quality of shale oil, inefficient utilization of retorting gas, and the unsatisfactory economic performance. In the situation of the low oil price, many oil shale refinery plants are forced to stop or cut production. Thus, oil shale industry is facing a severe problem. How to relieve monetary loss or turn it into profits? This paper proposes three integrated oil shale refinery processes: an integrated with hydrogen production from retorting gas, an integrated with hydrogenation of shale oil, and an integrated with hydrogen production and oil hydrogenation. The techno-economic performance of the three different processes is conducted and compared with that of a conventional oil shale process. Results show the exergy destruction ratio of the oil shale process integrated with hydrogen production from retorting gas is the least, 41.6%, followed by the oil shale process integrated with hydrogen production and oil hydrogenation, 45.9%. Furthermore, these two proposed processes have the best economic performance. Especially they can turn losses of the conventional oil shale process into profits at the situation of low oil price. The oil shale process integrated with hydrogen production from retorting gas is recommended to the oil shale plants which use the oil shale with oil content lower than 12.9%, while the plants using oil shale with oil content higher than 12.9% are better to select the oil shale process integrated with hydrogen production and oil hydrogenation.

Taking natural gas from marine strata of the Wufeng–Longmaxi Formation in the Jiaoshiba Block of the Fuling Shale Gas Field as a research subject, the analyses of the gradients of shale gas and carbon isotope shows that the natural gas from the Jiaoshiba area belongs to a high-quality hydrocarbon gas. The contents of methane range 97.22%–98.41%, with a little amount of ethane and propane, an average wetness of 0.74%, and little amount of non-hydrocarbons such as CO 2 , N 2, H 2, however, there's no H 2 S. The carbon isotopes of methane, ethane, and propane are characterized by their complete isotopic reversal (δ 13 C 1 > δ 13 C 2 > δ 13 C 3) . The natural gas from the Wufeng–Longmaxi Formation comes from the source rocks of the same formation, it classifies as a typical shale gas. According to the statistical determination criterion, natural gas in the Jiaoshiba area is derived from the sapropelic source rocks, which is a result of high-temperature pyrolysis. It is the product of mixing primary kerogen pyrolysis and secondary pyrolysis of crude oil, with apparent features of secondary pyrolysis of oil. The reason for the complete carbon isotopic reversal is the mixing of the two aforementioned gasses. Moreover, it has some sort of relationship with the loss function of shale gas after the Late Yanshan.

Oil shale is a complex fossil material that is composed of organic matter and mineral matrix. The thermal decomposition of the organic matter generates liquid and gaseous products. Oil shale is a porous rock containing kerogen, an organic bituminous material. Kerogen is a solid mixture of organic compounds that is found in certain sedimentary rocks. The kerogen can be pyrolyzed and distilled into petroleum-like oil. Oil shale and bituminous materials are suitable for obtaining petroleum-like products. The process designed in this study has the ability to control unwanted volatile materials. The mineral matter is removed from oil shale before pyrolysis. The pyrolysis of the oil shale is performed in a retort. The temperature at which the kerogen decomposes into usable hydrocarbons begins at 300°C, but the decomposition proceeds more rapidly and completely at higher temperatures. Decomposition takes place most quickly at a temperature between 475 and 525°C. Shale oil from oil shale consists of the h...

Summary Horizontal wells combined with successful multistage-hydraulic-fracture treatments are currently the most-established method for effectively stimulating and enabling economic development of gas-bearing organic-rich shale formations. Fracture cleanup in the stimulated reservoir volume (SRV) is critical to stimulation effectiveness and long-term well performance. However, fluid cleanup is often hampered by formation damage, and post-fracture well performance frequently falls to less than expectations. A systematic study of the factors that hinder fracture-fluid cleanup in shale formations can help optimize fracture treatments and better quantify long-term volumes of produced water and gas. Fracture-fluid cleanup is a complex process influenced by multiphase flow through porous media (relative permeability hysteresis, capillary pressure), reservoir-rock and -fluid properties, fracture-fluid properties, proppant placement, fracture-treatment parameters, and subsequent flowback and field operations. Changing SRV and fracture conductivity as production progresses further adds to the complexity of this problem. Numerical simulation is the best and most-practical approach to investigate such a complicated blend of mechanisms, parameters, their interactions, and subsequent effect on fracture-fluid cleanup and well deliverability. In this paper, a 3D, two-phase, dual-porosity model was used to investigate the effect of multiphase flow, proppant crushing, proppant diagenesis, shut-in time, reservoir-rock compaction, gas slippage, and gas desorption on fracture-fluid cleanup and well performance in Marcellus Shale. The research findings have shed light on the factors that substantially constrain efficient fracture-fluid cleanup in gas shales, and we have provided guidelines for improved fracture-treatment designs and water management.

India recognizes the strategic importance for developing shale gas resources like other countries in the world. Shale gas reservoirs are known to be difficult for extracting gas in comparison to conventional reservoirs. Recently, due to high prices of gas, rising demand and enhancement in recovery technologies has attracted the Indian energy industries to explore the shale gas resource. Coal and lignite are the prime source of energy in India and these resources are well explored, while shale is ignored, despite it being associated with coal and lignite bearing formations. The paper presents reservoir characteristics of shale horizons in Barren Measures and Barakar formations of north and south Karanpura coalfields. Shale core samples were collected from exploratory boreholes in air tight canisters. In-situ gas content and adsorption capacities ascertained to be 0.51–1.69 m3/t and 3.90–5.82 m3/trespectively. Desorbed gas derived from canisters contains CH4, C2H6, C3H8, CO2, N2 and O2 and varies from 76.19–82.63, 0.38–0.76, 0.10–0.50, 8.65–12.34, 9.89–19.34 and 0.56–2.24 vol. % respectively. The permeability and porosity determined under reservoir simulated confining pressure is varying from 0.41–0.75 mD and 0.89–2.28 % respectively. The plots of Rock Eval S2vs TOC and HI against Calc. VRo% indicates that all shale samples belong to Type III kerogen, which is prone to generate gas. It is evaluated that insitu gas content, sorption capacity, saturation level and low permeability of shale beds are critical parameters for development of shale gas resource in the studied area.

Shale gas in nonmarine facies has attracted less interest compared with the marine facies. The Ordos Basin is one of the Jurassic nonmarine continental coal basins in northern China. Several exploration wells have revealed the existence of shale gas resources in the Middle Jurassic Yan’an Formation in this basin. The Yan’an Formation is the coal-measures in this basin, dominated by an intercalation of siliciclasitcs and thick coals, and the shales were mainly developed in the fluvial, lacustrine and lacustrine delta environments. The shales are multi-inerlayered with sandstones and coals, and have an unstable horizontal distribution. characterized by a small thickness of individual layer (ranging between 0.1 m and 34.77 m), and large thickness of the total cumulative layers (up to 380 m). The shales have intermediate to high contents of total organic carbon (ranging from 0.24% to 5.82%) and low thermal evolution degree in an immature-mature stage. The gas is mainly of biogenic origin, with relatively small fraction of thermogenic origin. The mineralogy investigation revealed that the shale have a lower content of brittle minerals and a high content clay minerals. The pore types are dominated by dissolution pores, intergranular pores, intragranular holes and micro cracks, and few organic holes can be seen. The porosity and permeability are low, with significant reservoir heterogeneity. The gas content in this nonmarine shale is low, dominated by adsorption phase. The shale gas in this basin were generally/enclosed within the groundwater flow closure zones, where the groundwater salinity is relatively low. The development characteristics of the shale and shale gas were also controlled by the depositional facies, and the conditions for hydrocarbon generation, reservoir performance, and gas preservation, can be favorably developed in the lacustrine facies, followed by the lacustrine delta facies, while the conditions in the fluvial facies are relatively poor. Although the resource potential of shale gas in the nonmarine continental coal-measures is lower than that of the marine facies, the shale gas, coal, coalbed methane, and tight sandstone gas often coexist in the continental coal basins which may support a more prospect energy scenario. Therefore, comprehensive exploration and collaborative development of the shale gas, coalbed methane and tight sandstone gas in the continental basin may be an ideal way to synthetically utilize the continental coal-measure gases.

With the decrease of conventional energy reserves, countries such as China began to explore efficient ways to use oil shale as an alternative energy source. The refinery technology used for oil shale is retorting. However, in this process, fine-particle shale, semi-coke, and retorting gas are not used efficiently; rather, they are dismissed as solid and gaseous wastes. Resource utilization is extremely low in retorting. In addition, the price of crude retorting oil is very low, making the whole retorting process suffer from a low economic benefit. In this paper, a new oil shale comprehensive refinery process is proposed, aiming to process shale particles from all ranges of sizes. The new process includes a gas circulation shale retorting unit, a Dagong shale retorting unit, an oil–gas separation unit, a retorting gas steam reforming unit for hydrogen production, and a shale oil hydrogenation unit. Fine-particle shale from the gas circulation shale retorting unit is used as raw material in the Dagong shale...

The results of experimental studies on preparation of oil shale and oil residue blend for gasification to produce synthesis gas of the desired composition are reported. The feasibility of preparation of stable oil shale suspension in aqueous emulsion of high-viscosity residual fuel oil having structural-rheological characteristics that ensure unhindered pumping of gasification feedstock through the gas generator nozzle and uniform distribution in the combustion chamber is shown.

Due to termination of work at the Leningrad Shale Deposit, the Russian shale industry has been liquidated, including not only shale mining and processing but also research and engineering (including design) activities, because this deposit was the only commercially operated complex in Russia. UTT-3000 plants with solid heat carrier, created mainly by the Russian specialists under scientific guidance of members of Krzhizhanovsky Power Engineering Institute, passed under the control of Estonian engineers, who, alongside with their operation in Narva, construct similar plants in Kohtla-Jarve, having renamed the Galoter Process into the Enifit or Petroter. The main idea of this article is to substantiate the expediency of revival of the oil shale industry in Russia. Data on the UTT-3000 plants' advantages, shale oils, and gas properties is provided. Information on investments in an UTT-3000 plant and estimated cost of Leningrad oil shale mining at the Mezhdurechensk Strip Mine is given. For more detailed technical and economic assessment of construction of a complex for oil shale extraction and processing, it is necessary to develop a feasibility study, which should be the first stage of this work. Creation of such a complex will make it possible to produce liquid and gaseous power fuel from oil shale of Leningrad Deposit and provide the opportunity to direct for export the released volumes of oil and gas for the purposes of Russian budget currency replenishment.

The geological conditions and exploration potential of shale oil in Chang7 Member, Upper Triassic Yanchang Formation, Ordos Basin, were studied from various aspects, including petrographic characteristics, storage ability, geochemical features, friability and mobility of hydrocarbon in the source rock, etc. A classification criterion of lithofacies for Upper Triassic Chang 7 source rock in Ordos Basin were established based on the correlation between lithology, organic carbon content and logging parameters, from which, the spatial distribution and development scale of two types of shale, black shale and dark massive mudstone, have been predicted. Qualitative and quantitative characterization of the micro-structures of Chang7 source rock using state-of-the-art microscopic facilities including argon ion milling – field emission scanning electron microscopy (FESEM), focused ion beam scanning electron microscopy (FIB-SEM) and Nano-CT reveal that the dominant pore types in Chang7 source rock are intra-granular pores and inter-granular pores; the pores and throats in the two kinds of lithofacies are both nano-scale, and the dark massive mudstone has better physical properties than the black shale. The Chang7 shale oil resources and mineability were evaluated based on the parameters from geochemical experiments on the source rock, including pyrolysis S1, chloroform bitumen ‘A’, TOC and thermal maturity, free hydrocarbon content, as well as geo-mechanical properties such as brittle mineral content and development of fractures. With large scale of favorable lithofacies, good storage ability and abundant hydrocarbon, Chang7 Member has the material basis for shale oil occurrence and accumulation, in addition, the shale oil there has accumulated greatly and has favorable properties for flowing in nano-scale pores and throats. All these show that Chang7 Member has high potential for shale oil exploration, in which, the dark massive mudstone is a more favorable target for shale oil exploration under the present technical conditions. Key words: Ordos Basin, Triassic Chang 7 Member, shale oil, geological condition, exploration potential

A thermogravimetry analyzer was employed to investigate the effect of the shale core on the combustion reactions of the tight oil from the Wolfcamp shale reservoir for the air injection process (AIP). The result indicated that the shale cuttings show strong catalytic effect on tight oil combustion process. A considerable amount of coke was formed at the end of the fuel deposition stage after the addition of shale cuttings. This phenomenon could be beneficial for the combustion process at the high-temperature combustion stage, which is favorable for the implementation of the AIP with a shale oil reservoir.

The complex analysis of the chemical composition and technological properties of oil shale from the Green River formation was carried out. The technical characteristics and granulometric composition of test samples and the element compositions of the mineral and organic matters of shale rocks were determined. The structure of organomineral aggregates formed upon the crushing of shale rocks was studied by electron microscopy. Based on the experimental data, a procedure was developed for the separation of kerogen from the oil shale by physicochemical processing.

In order to better understand the generation and primary source of mature thermogenic gas in shale, and to evaluate the residual gas generation potential of the shale at different maturity levels, we performed pyrolysis experiments on an organic-rich marine shale and its kerogens prepared by artificial maturation. The results indicate that the thermal maturation of organic matter in the shale can be divided into four stages: oil generation ( 2+ hydrocarbon gases are produced during condensate and wet gas generation. The kerogen at a thermal maturity of >3.0% EasyRo still has methane generation potential. Whether or not gas generation potential of a highly mature kerogen has a commercial significance depends on its organic matter richness, thermal maturity internal and some other geological factors, such as caprock sealing property, reservoir physical property, and tectonic movement. In addition to the gas produced from kerogen cracking, gas is also generated from the secondary cracking of residual bitumen as maturation progresses. Early hydrocarbon expulsion during oil generation likely has a considerable effect on the amount and δ 13 C values of the late-generated shale gas. The lower the oil expulsion efficiency of a shale, i.e., the more retained bitumen, then the higher the productivity of post-mature shale gas and comparative enrichment of the latter in 1 2 C.

Taking Well JY4 as example, the authors present petroleum system modeling with PetroMod software for shale gas resource assessment of Wufeng-Longmaxi shale in Jiaoshiba area, which takes account of hydrocarbon adsorption process within source rocks. On the basis of burial and thermal modeling, source rocks adsorption parameters obtained from isothermal adsorption of gas measurements were defined. The results show that the total gas content of Wufeng-Longmaxi shale is estimated in rang of 4.6–10.5 * 106 kg/km2, and the proportion of absorbed gas content is around 22–50% in Jiaoshiba area.

Rock-Eval pyrolysis data are used for assessments of the quality and maturity of potential hydrocarbon source rock, but is also often applied among shale oil studies to estimate the so-called “total oil” for Oil In Place (OIP) calculations. However, for these approaches Rock-Eval may underestimate total oil due to a “carryover effect”, a bias which is particularly crucial for shale oil investigations. In this study we examined the total oil of marine to lacustrine source rocks from German shale oil formations using data from Rock-Eval combined with solvent extraction. Each source rock was analysed by Rock-Eval both non-extracted and extracted to obtain values for total oil (= [S1whole rock − S1extracted rock] + [S2whole rock − S2extracted rock]). Comparison of these two data sets revealed that for the individual formations in average 17–23% of the S2 fraction is extractable, herein termed “S2 oil”. This “S2 oil” increases the total oil amount compared to the conventional free oil (S1) by average factors of 2.2–3.6. For selected source rocks the molecular composition of the “S2 oil” was obtained by a specific approach: Rock-Eval analysis was terminated after S1-detection at 301 °C, samples were retrieved, solvent extracted and analysed by gas chromatography. Depending on the type of organic matter and maturity, the “S2 oil” contains significant amounts of higher boiling hydrocarbons such as n-alkanes but also contributes to the unresolved complex mixture. It is to date unclear, how much of this “S2 oil” should be finally considered as technically mobilized shale oil.

Because of enrichment of kerogen in the beneficiation process, oil shale may be used more effectively in both oil production and power generation. The float and sink tests were carried out to separate the raw oil shale samples into a series of fractions according to density first. Density distribution of Longkou oil shale in China indicated the ash content of oil shale with different density fractions increased with the increasing of density fraction, and the inorganic minerals composition of oil shale was mainly quartz, kaolinite, montmorillonite, calcite, analcime, dolomite, and pyrite. Comprehensive considering the results of XRF, XRD, and optical microscopy of Longkou oil shale in each density fraction all indicated there was high content of kerogen in low density fraction of oil shale. Although it is difficult to separate pure kerogen from oil shale, relative beneficiation of kerogen from raw oil shale could be realized using the gravity separation method. After the separation of raw oil shale using ...

Organic-rich shale deposited in a lacustrine environment is well developed in China and considered to contain a large amount of shale hydrocarbon resources. The Lower Jurassic Badaowan shale in the Junggar Basin is a typical lacustrine deposit that is regarded as the most significant source of natural gas. This study describes the geological and geochemical features of Lower Jurassic Badaowan shale and investigates its hydrocarbon resource. The Badaowan shale has fair to good hydrocarbon potential, and contains dominantly type III gas-prone organic matter (OM). Its thermal maturity ranges from immature to gas window (Ro, 0.5%–1.2%) and increases from north to south. However, In comparison with that of typical marine gas shales, the thermal maturity of Badaowan shale is lower at similar depths. X-ray diffraction (XRD) analyses show that lacustrine shale is fairly homogeneous and dominated by clay and brittle minerals. The clay minerals are dominated by illite and mixed illite/smectite. Observation made with a scanning electron microscopy (SEM) shows that intra particle (IntraP) pores and inter particle (InterP) pores are well developed, OM pores appears rarely due to its relatively low thermal maturity. A large thermogenic gas resource may occur in the southern basin. Unfortunately, potential gas shale in the southern Junggar basin is buried deeper than 6000 m, high costs and reduced permeability will make future exploration and development risky. Generally, the low thermal maturity and high clay content of Badaowan shale result in challenges to successful shale gas production.

On the 28th of November 2012, high shale gas flow was confirmed to be 203 × 10 3 m 3 in Longmaxi Formation; this led to the discovery of the Fuling Shale Gas Field. On the 10th of July in 2014, the verified geological reserves of the first shale gas field in China were submitted to the National Reserves Committee. Practices of exploration and development proved that the reservoirs in the Fuling Shale Gas Field had quality shales deposited in the deep-shelf; the deep-shelf had stable distribution, great thickness with no interlayers. The shale gas field was characterized by high well production, high-pressure reservoirs, good gas elements, and satisfactory effects on testing production; it's from the mid-deep depth of the quality natural gas reservoirs that bore high pressure. Comprehensive studies on the regional sedimentary background, lithology, micropore structures, geophysical properties, gas sources, features of gas reservoirs, logging responding features, and producing features of gas wells showed the following: (1) The Longmaxi Formation in the Fuling Shale Gas Field belongs to deep-shelf environment where wells developed due to organic-rich shales. (2) Thermal evolution of shales in Longmaxi Formation was moderate, nanometer-level pores developed as well. (3) The shale gas sources came from kerogens the Longmaxi Formation itself. (4) The shale gas reservoirs of the Fuling Longmaxi Formation were similar to the typical geological features and producing rules in North America. The findings proved that the shale gas produced in the Longmaxi Formation in Fuling was the conventional in-situ detained, self-generated, and self-stored shale gas.