Solid Bitumen Research Articles

Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan

A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70–90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43–10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Δlog R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C19 tricyclic terpanes, C30 pentacyclic triterpanes, and C27 steranes. Maturity parameters (Tmax, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C23 TT, the lower amounts of C29/C30 17α(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., Tmax, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, ββ/ββ+αα), and the hopane Ts/(Ts + Tm) and C31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.

Biomarkers and Re–Os geochronology of solid bitumen in the Beiba Dome, northern Sichuan Basin, China: Implications for solid bitumen origin and petroleum system evolution

Solid bitumen is ubiquitous in the Sinian Dengying Formation dolomite, a crucial gas reservoir in the Sichuan Basin. We use biomarkers and Re–Os geochronology, coupled with burial-thermal evolution history to trace the source and formation timing of the solid bitumen, and to reconstruct the petroleum system evolution in the Dengying Formation of the Beiba Dome, northern Sichuan Basin. The bitumen reflectance (Rb) values of solid bitumen range from 1.92 to 3.95%, with the solid bitumen showing no fluorescence, indicating that the solid bitumen in the Dengying Formation dolomite has a high thermal maturity, which consequently belongs to pyrobitumen formed by thermal cracking of crude oil. The isoprenoids and terpanes indicate that the solid bitumen was sourced from a marine shale deposited under a reducing environment. The C27–C29 regular sterane distribution of the solid bitumen is consistent with the Lower Cambrian Guojiaba Formation (Є1g) organic-rich shale, indicating that the solid bitumen was derived from the Є1g shale, rather than dolomite or shale within the Dengying Formation. The burial-thermal evolution history indicates that initial oil generation began in the Late Cambrian to the Early Silurian. Since the Early Permian, the Є1g organic-rich shale re-entered the oil generation window, and formed a giant paleo-oil accumulation during the Late Triassic. Thermal cracking of crude oil occurred from the Late Triassic to the Early Cretaceous forming the extensive solid bitumen. The Re–Os isotopes of solid bitumen yield two similar isochron ages of 128.1 ± 7.3 Ma and 126.2 ± 8.0 Ma, which represents the timing of thermal cracking termination, i.e. the final timing of dry gas generation. This work highlights that the Re–Os geochronology has great potential to constrain the absolute timing of evolution of the petroleum system.

Movement of native fluids during scanning electron microscopy imaging of petroliferous siltstones: Evidence from the Montney Formation, western Canada

The nature and distribution of native fluids, both hydrocarbons and water, exert fundamental control on the petrophysical properties and fluid dynamics of unconventional, low-permeability reservoir rocks. Here, we report dynamic native fluid phenomena that occurred serendipitously during scanning electron microscopy (SEM) imaging of petroliferous siltstones from the Triassic Montney Formation of western Canada. These observations of fluid movement provide rare in-situ contextual information about the nm-to μm-scale distribution of fluids in tight unconventional reservoirs. Dynamic oil behaviour is indicated by expulsion structures that formed in pore-filling solid bitumen when trapped oil erupted from the sample while under vacuum pressure conditions. These structures strikingly show that oil and solid bitumen intimately coexist within the pore network of tight rocks in the oil reservoir-fluid window. Dynamic brine behaviour is evident from strings of halite crystals overlying pores between minerals. The halite crystals precipitated from hypersaline brine that migrated from the interior to the surface of the sample. This behaviour indicates well-connected brine exists in Montney siltstone pores, even those substantially filled with hydrophobic solid bitumen. These SEM observations support previous petrophysical studies that suggest the electrical conductivity of Montney rocks is controlled primarily by their bulk volume of well-connected hypersaline water.

Indication of hydrocarbon migration in the Western Mecsek Mountains evidenced by fluid inclusion chemostratigraphy

Primary and secondary hydrocarbon-bearing fluid inclusion (HCFI) assemblages occur in the Middle Triassic Lapis Limestone in the Szuadó Valley of the Western Mecsek Mts. The primary HCFIs were trapped in saddle dolomite crystals, and the secondary HCFIs were enclosed in calcite neospar and fracture-filling calcite. Solid bitumen is also present along fractures. The volatile compounds liberated from fluid inclusions are characterized by non-hydrocarbon and hydrocarbon species. The fluorescent properties of HCFIs, the occurrence of the solid bitumen, as well as the composition of inclusion oils indicate the migration of light oils through the Lapis Limestone. Petrographic observations suggest a prolonged oil charge event, which resulted in HCFIs beeing trapped under evolving diagenetic conditions.

Application of fluorescent light microscopy to enhanced lithofacies analysis of Jurassic carbonate rocks, SE Bohemian Massif

Upper Jurassic limestones and dolomites of the Vranovice Formation occur on the southeastern slopes of the Bohemian Massif below the Western Carpathian thrust belt. They represent a special type of reservoir rocks in the potential geothermal systems and exhibit highly variable porosity, permeability, and flow mechanisms due to different type of diagenesis and pervasive dolomitization. Fluorescence and translucent light microscopy was used for more detailed petrographic analysis of Vranovice limestones and dolomites. Isopachous, syntaxial and dolomitic cements were distinguished along with fossils recrystallization. Two generations of dolomite were identified – replacement dolomite and zonal cementation dolomite, what suggests a number of changes in the formation water chemistry during the dolomitization process. Extent of the observed dolomitization is inversely related to the porosity of the Jurassic rocks. Postdiagenetic generation of fissures cutting the strata due to tectonic deformation is documented by bright fluorescent color. In the studied samples of Vranovice limestones and dolomites the fissures represent the most important migration pathways, more than pore throats themselves. Further genetic information on petoleum migration is interpreted from intercrystalline porosity filled with precipitated solid bitumen. Present results provide basis for further investigations in pore-water-rock interactions and changes in chemical conditions during diagenesis.

The significance of organic matter–mineral associations in different lithofacies in the Wufeng and longmaxi shale-gas reservoirs in the Sichuan Basin

The occurrence and enrichment of organic matter (OM) are influenced by the deposition of minerals in shale reservoirs. However, inadequate research has been published on the origin, spatial relationships, and significance of organic matter–mineral associations (OMMA) for predicting “sweet spots” in shale gas reservoirs. We describe OMMA in the Wufeng Formation and the Longmaxi Formation in the Sichuan Basin, which is the largest commercial shale gas accumulation outside of North America. We characterize the presence of solid bitumen (SB) and graptolite fragments (the most important kinds of OM in these reservoirs) with four important minerals: i.e., quartz, clay minerals, carbonates, and pyrite. The occurrence of OMMA is influenced by the physical (e.g., morphology, texture, and density) and chemical properties of the associated minerals, which influences the accumulation of OM and the development of porosity. By carefully studying the type and relative amount of OM, we have determined how the surface porosity, pore diameters, and amount of porosity in each kind of OMMA influence the quality of shale gas reservoirs: e.g., diagenetic quartz or clay minerals encased in SB is the most favorable kind of OMMA. The quality of OM–carbonate associations is lower because they contain a relatively low amount of OM. Similarly, the relatively low abundance and dispersed distribution of OM–pyrite associations do not improve the quality of shale gas reservoirs. We identified four important lithofacies using the color, composition, and sedimentary structures of samples. The heterogeneous distribution of OMMA has important implications for shale gas reservoirs by influencing hydrocarbon generation and gas storage conditions in each lithofacies: i.e., siliceous shale > argillaceous siliceous shale > calcareous shale > silty shale.

Hydrocarbon occurrence characteristics and charging differences in Chengbei Fault Zone based on fluid inclusions

Hydrocarbon accumulates in multiple layers of the high, middle and low parts of Chengbei fault zone, in vicinity of Qikou Sag and Qinan Subsag, which represents a breakthrough for large-scale hydrocarbon exploration in recent years. Based on the size, abundance, and attitute of hydrocarbon inclusions, as well as their microscopic polarization and fluorescence characteristics, the hydrocarbon occurrence and the charging difference in the high, middle and low faulted terraces were analyzed systematically in this paper. There are two types of occurrence in the intergranular pores and fractures in the reservoirs, namely, the medium to light oil that shows green fluorescent light, and the solid bitumen charged with a certain amount of hydrocarbon that does not show any fluorescent light. This indicates that the zone has experienced at least two stages of hydrocarbon migration and accumulation, and that diversified forms of hydrocarbon exist in the reservoirs of the zone. The characteristics of hydrocarbon inclusions show that two stages of inclusions were found in the tectonic positions of different faulted terrace. The first-stage inclusions were developed in the early secondary enlargement of quartz grains, with a low degree of development abundance; while the second-stage inclusions were developed after the secondary enlargement of quartz grains, with a high degree of development abundance. The second-stage hydrocarbon inclusions of the reservoir samples obtained at tectonic positions of the high, middle and low fault terrace represent the main filling stage of the present-day reservoirs. Their fluorescence characteristics demonstrate the oil charging difference, which is the maturity of the hydrocarbon decreases as the terraces lift up along the slope. Identifying the hydrocarbon occurrence and charging differences from the perspective of inclusions is conducive to recognizing the regularity of hydrocarbon charging and migration and the distribution patterns in fault terrace zones, and lay the foundation for hydrocarbon exploration of slopes in the future.

The genesis of solid bitumen and its effect on reservoir physical properties

ABSTRACT Solid bitumen has been found widely in the reservoir of Mahu sag. The geochemical characteristics and genesis of solid bitumen are not well understood. At the same time, the presence of bitumen can block the pore space and affect the physical properties of the reservoir, which seriously restricts the exploration and development of the reservoir in this area. Based on the analysis of bitumen geochemical characteristics and the comparison of reservoir physical properties before and after bitumen dissolution, this paper systematically studied the genesis of the reservoir bitumen and its effect on the reservoir physical properties. The results are as follows. (1) After the oil reservoirs generated in early stage of hydrocarbon expansion of source rocks of the Fengcheng Formation were subjected to biodegradation, they were then subjected to thermal alteration and deformation into bitumen after normal crude oil filling in the later period. (2) Bitumen is black under the microscope, mainly distributed in various cracks such as micro cracks and dissolved pores. (3) After the solid bitumen was dissolved, the average increase of sample density, porosity and permeability is 0.03 g/cm3, 4.12% and 14.48mD, respectively, and the solid bitumen content was positively correlated with the change in porosity, permeability, and density. The relationships are as follows: Y1 = 0.702x+2.3796; Y2 = 6.113x-0.6423; Y3 = 0.0115x-0.0003. The research has important guiding role for the exploration and development of reservoirs in Mahu sag and similar areas.

Constraints of molecular and stable isotopic compositions on the origin of natural gas from Middle Triassic reservoirs in the Chuanxi large gas field, Sichuan Basin, SW China

Abstract The Middle Triassic Leikoupo Formation in the Sichuan Basin is a gypsum-bearing stratum. The Chuanxi (CX) large gas field has been recently discovered in Middle Triassic reservoirs, with a controversial gas source. The gas geochemistry is analyzed in this study to investigate the gas origin and source. The H2S-bearing dry gas in the CX gas field has an H2S content ranging from 1.07% to 4.09%, with a gas souring index (GSI) of 0.0120–0.0438. The δ13C1, δ13C2, and δ2HCH4 values range from –31.8 to –30.4‰, from –32.9 to –29.6‰, and from –153 to –136‰, respectively. Genetic identification based on the geochemical characteristics suggests that the gas is an oil-type and derives from the secondary cracking of oil. According to the GSI and alkane carbon isotopes, the gas experienced weak TSR alteration without ethane. Potential high-quality source rocks include the Upper Permian mudstones and marlstones, as well as the Lower Cambrian mudstones, with a total organic carbon content generally higher than 2.0%. A comparison of the carbon isotopic compositions between ethane in the gas and kerogen and the hydrogen isotopic compositions of methane implies that natural gas has an affinity with the Upper Permian rather than the Lower Cambrian source rocks. The extremely low development of solid bitumen in the reservoirs suggests the inexistence of large-scale paleo-oil pools in the Leikoupo Formation. The Middle Triassic natural gas in the CX gas field originates from the Upper Permian Longtan Formation, where the gas pools are dominated by direct filling of secondary cracking gas.

Examination of inertinite within immature Eagle Ford Shale at the nanometer-scale using atomic force microscopy-based infrared spectroscopy

The nanoscale molecular composition of sedimentary organic matter is challenging to characterize in situ given the limited tools available that can adequately interrogate its complex chemical structure. This is a particularly relevant issue in source rocks, as kerogen composition will strongly impact its reactivity and so is critical to understanding petroleum generation processes during catagenesis. The recent advent of tip-enhanced analytical methods, such as atomic force microscopy-based infrared spectroscopy (AFM-IR), has allowed for the major compositional features of kerogen and other types of in situ organic matter to be elucidated at spatial resolutions at or below 50 nm. Here AFM-IR was applied to examine inertinite, an important organic matter type, present in a thermally immature Eagle Ford calcareous mudstone. The data show that the nanoscale molecular composition of the examined inertinite is (i) less heterogeneous than solid bitumen in more thermally mature Eagle Ford samples and (ii) more hydrogen- and oxygen-rich than inertinite examined in the New Albany Shale.

Characterization and interpretation of organic matter, clay minerals, and gas shale rocks with low-field NMR

Nuclear magnetic resonance (NMR) has emerged as an essential method for appraising gas-shales, quantifying their petrophysical properties, classifying their fluid types, and discerning their productivity. Comprehensive measurement campaigns, as well as reliable thermal-heating experiments, are required to fully understand the NMR mechanism of shale and to further develop future gas-shale exploitation strategies. NMR signatures from individual matrix components, which comprise shale, are investigated to gather data to better estimate its petrophysical parameters. Subsequently, we perform T1 and T2 measurements of kerogen, solid bitumen, and clay minerals. Next, we analyze the temperature effect on the NMR signal interpretation of different compositions of gas-shale samples in detail, coupled with the position of clay minerals and solid bitumen from the T1-T2 mapping. A shale plug sample was quantified by the NMR T1-T2 relaxation signals under initial conditions and different temperature conditions of 110 °C, 250 °C, 450 °C, and 650 °C. The fluid volume significantly decreased as the temperature increased. The organic matter maturity changed at 450 °C and 650 °C. According to a thermal-heating experiment with powdered clays, we obtained the hydroxyl group and crystal water signals and determined the critical temperature for different dried types of water in clay mineral. It is reasonable to infer that deconvoluting the entire shale sample into different components can further determine the NMR relaxation mechanisms. The ultimate goal of this project was to develop a holistic methodology to understand the NMR mechanisms of isolated components and to assess the positions of kerogen, solid bitumen, illite, kaolinite, smectite, and chlorite from T1-T2 mapping. This work contributes to the fundamental understanding of shale formations by quantifying the NMR relaxation mechanisms of various constituents in shale and provides implications for shale rock evaluations.

Results of the study of shrinkage of heat-accumulating materials based on bitumen paraffin depending on temperature

The article presents the results of a study of the thermal properties of heat-accumulating materials based on bitumen paraffin. Heat-accumulating materials of a phase transition with a given melting point and phase transition obtained by mixing commercial solid bitumen paraffin and liquid paraffin and by mixing individual n-alkanes of a neighboring series were considered. It is shown that the sum of the enthalpies of melting and phase transition in the crystalline state thermal storage materials based on meta moderation depends on the width of the fractional part of the heat storage materials and cleanliness of the content of n-alkanes, from the fractional part of the heat storage material and the number of odd and even n-alkanes and their correlation, with the same melting point.

Making sense of pore systems and the diagenetic impacts in the Lower Triassic porous dolostones, northeast Sichuan Basin

As the heterogeneity of pore systems, carbonate rocks commonly exhibit unpredictable porosity vs. permeability relationship and make the exploitation and prediction of prolific reservoirs difficult. Most of published studies on pore systems were conducted in sandstones and shales, while carbonate rocks, especially dolostones have received little attention. In this study, we investigate the porous dolostone reservoir in the Lower Triassic Feixianguan Formation, northeast Sichuan Basin, of which the helium porosity is up to 28.9% and permeability is up to 3360 mD. High pressure mercury intrusion capillary pressure (MICP) tests and Field emission scanning electronic microscopic (FE-SEM) examinations reveal the coexistence of two types of open pore systems. One consists of interparticle and intercrystalline pores with large throats of >3 μm radii. The other consists of intraparticle pores with small throats of 0.06–1 μm radii. Intracrystalline pores in sucrosic dolostones are isolated and invalid for the storage or fluid flow. Two open pore systems are shown as two separated fractal segments, and the fractal dimensions are related to the throat-surface roughness and pore volume. Observed in thin sections, pores in some dolostones are occluded mainly by two sorts of calcite cement and solid bitumen. Furthermore, MICP analyses exhibit the difference between pre-bitumen and post-bitumen calcite cement, i.e., that pre-bitumen calcite destroys both two open pore systems while post-bitumen calcite only harms to the pore system of interparticle and intercrystalline pores with large throats of >3 μm radii. This difference might be due to the bitumen or its precursor oil.

Genesis of solid bitumen

This paper presents a new schematic model for generation and timing of multiple phases of solid bitumen throughout the continuum of organic matter maturation in source and tight reservoir rocks. Five distinct stages in the evolution of solid bitumen are proposed: (1) diagenetic solid bitumen (or degraded bituminite), which is not a secondary maceral resulting from the thermal cracking of kerogen. Instead it is derived from degradation of bituminite in the diagenesis stage (Ro < 0.5%); (2) initial-oil solid bitumen, is a consolidated form of early catagenetically generated bitumen at the incipient oil window (Ro ~ 0.5–0.7%); (3) primary-oil solid bitumen is derived from thermally generated bitumen and crude oil in the primary oil window (Ro ~ 0.7–1.0%); (4) late-oil solid bitumen (solid-wax) is derived from the waxy bitumen separated from the mature paraffinic heavy oil in the primary- and late-oil windows; and (5) pyrobitumen, which is mainly a non-generative solid bitumen, is evolved from thermal cracking of the remaining hydrocarbon residue and other types of solid bitumen in the dry gas window and higher temperature (Ro > 1.4%). This model shows concurrence of multi-populations solid bitumen with oil, bitumen, and other phases of fluid hydrocarbon residue during most of the maturity continuum.

Molecular structure and origin of solid bitumen from northern Sichuan Basin

Four natural solid bitumen samples were collected from the Guangyuan area (northwest Sichuan Basin, southwest China) to characterize their structure. Samples were ground to power (120 mesh), purified by ZnBr2 solution to remove mineral and soluble impurities, and analyzed using Rock-Eval pyrolysis, elemental analysis, Raman spectroscopy, solid bitumen reflectance, and solid-state 13C nuclear magnetic resonance to determine the maturity degree of samples and obtain structural information. Results showed that Guangyuan solid bitumen samples are in low maturity, and three solid bitumen maturity detection methods are compared in this research. With respect to the solid bitumen molecular structure, less than 10 carbon atoms were determined in aliphatic chains and the solid bitumen aromatic clusters ranged from two to four rings, which indicates that the solid bitumen comprises complex geological organic matter, such as kerogen. Four molecular models were established in this research to reflect the basic molecular configuration of natural solid bitumen. Samples were classified into two types based on the structural information and models, and the results imply that the solid bitumen samples may have been derived via different evolutionary processes. This phenomenon indicates that structural studies could play an important role in the research of oxidation and carbon isotope changes in solid bitumen. In summary, this investigation provides an understanding of the evolutionary stages of Guangyuan bitumen, establishes associated molecular structure models, and researches the role of structural information in bitumen source studies. As the focus of this study, the four molecular models were used to restore the structural characteristics of natural solid bitumen as possible. And this study tried to find out the relationship between the solid bitumen structure information and it geology evolution. As the carbon isotope may not accurately determine the source of solid bitumen because of oxidation, molecular information could be used to research the solid bitumen source and associated evolution.

Kerogen composition and maturity assessment of a solid bitumen-rich and vitrinite-lean shale: Insights from the Upper Jurassic Vaca Muerta shale, Argentina

Assessment of thermal maturity by solid bitumen reflectance measurements in vitrinite-lean or vitrinite-barren shales is widely used in unconventional shale gas and shale oil plays but the method is commonly challenged by the complexity in the measurements. The Upper Jurassic marine Vaca Muerta shale in the Neuquén Basin in western Argentina is both a prolific conventional source rock and a primary unconventional reservoir for oil and gas. The shale is rich in solid bitumen and lean or barren in vitrinite and offers an excellent opportunity to gain insight into thermal maturity assessment of a shale with a complex organic matter composition. The kerogen composition of a set of immature to highly mature Vaca Muerta shale samples was investigated by organic petrography and reflectance measurements were taken on vitrinite and solid bitumen. The results were integrated with available Rock-Eval data and stable carbon isotope values of shale gas (ethane and propane) collected at the same depth as the rock samples. The maceral composition of immature Vaca Muerta shale is highly sapropelic and oil-prone with Hydrogen Index values of 600 mg HC/g TOC or higher. The liptinite macerals consist primarily of alginite with minor amounts of inertinite and/or oxidized vitrinite. Indigenous vitrinite is generally scarce and in some samples absent. Vitrinite reflectance values range from 0.79%Ro to more than 1.94%Ro corresponding to early peak oil to dry gas maturity. Solid bitumen is abundant in all mature samples. Two general types of solid bitumen morphology were observed: (i) BR I, a dark reflecting porous variant disseminated in the clayey mineral matrix and (ii) BR II, a lighter reflecting more ‘dense’ textured variant. Bands of denser solid bitumen were commonly seen ‘flowing’ in more porous or weak zones in the matrix and around mineral grains. Degassing pores were frequently observed. Solid bitumen reflectance measurements on BR I and BR II provided two populations with different reflectance ranges. The correlation between vitrinite and BR II reflectances is considered to have highest confidence. The correlation can be expressed by the equation VReqv = (BR II + 0.3043)/1.026. The established VReqv-BR II correlation yields results comparable to other published correlations but also demonstrates significant discrepancy to others. This warrants caution when assessing the maturity of complex unconventional shale gas and oil plays by translating solid bitumen reflectance values into vitrinite reflectance equivalents using correlations not calibrated to that specific shale play. Both Hydrogen Index values and ethane and propane stable carbon isotope values of Vaca Muerta shale gas show strong correlations to VReqv derived from BR II. Thus, in cases with absence of vitrinite and questionable solid bitumen measurements reasonable maturities (vitrinite reflectance equivalents) can be inferred from these relationships.

Dating and characterizing primary gas accumulation in Precambrian dolomite reservoirs, Central Sichuan Basin, China: Insights from pyrobitumen Re-Os and dolomite U-Pb geochronology

Primary gas accumulation with trillions of cubic meters of gas volumes was discovered recently in the Precambrian Dengying Formation of the Gaoshiti-Moxi block, Central Sichuan Basin, China. In this study we investigated the pervasive saddle dolomite cements and solid bitumens within karst vugs in the Dengying dolomite reservoirs. Using laser ablation-inductively coupled plasma-mass spectrometry (LA-ICP-MS) in situ U-Pb dating, we obtained a high-precision absolute age of 259.4 ± 3.0 Ma for the saddle dolomite cementation, consistent in timing with the eruption of Emeishan flood basalts (262–251 Ma). Combined with high homogenization temperatures (Th) and salinities of primary fluid inclusion, as well as rare earth element (REE) compositions, we consider that the saddle dolomite precipitation was likely related to hydrothermal activity driven by the Emeishan mantle plume.The identification of rare surviving oil inclusions and extensive solid bitumens within the dolomite vugs is indicative of the presence of paleo-oil reservoirs. These bitumens are characterized by high equivalent vitrinite reflectance (Requ), no fluorescence, and deformed fibrous textures, typical of highly mature pyrobitumens. Gas geochemistry data indicates that only minor thermochemical sulfate reduction (TSR) has occurred. Thus the pyrobitumen was interpreted to result mainly from the thermal cracking of paleo-oils, and its associated Re-Os isochron age of 154 ± 21 Ma, representing the timing of dry gas formation. Petrographical evidence suggests that the paleo-oil charge must have taken place after sparry dolomite cementation but prior to pyrobitumen generation. This, combined with coeval aqueous inclusion Th data and published thermal-burial models, constrains the time of paleo-oil emplacement to ca. 222–205 Ma, suggesting an oil-filling event related to the Indosinian Orogeny. This study documented the first chronological data constraining the complex evolution history of a petroleum system in one of the oldest primary gas reservoirs in the world.

Optical parameters and microstructural properties of Solid Bitumens of high reflectance (Impsonites). Reflections on their use as an indicator of organic maturity

Six solid bitumen samples from Paja Formation (Cretaceous of Colombia) were optically, chemically and structurally characterized using bulk chemistry, reflectance indicating surface (RIS), micro-Raman and X-ray diffraction (XRD) parameters. The volatile matter and carbon contents and high random reflectance (Ro%) placed these solid bitumens in the category of cata-impsonites according to Jacob's classification. RIS axes (RMAX, RINT and RMIN) form almost a sphere, and consequently, the anisotropy (Ram or bireflectance values) of these materials is very weak, comparatively to other carbonaceous materials (coals) of similar degree of evolution. The weak anisotropy character of the solid bitumen is related to the absence of pressure in the system, which did not promote the orientation of the basic structural units (BSUs) in a three-dimensional arrangement. The degree of ordering evaluated by Raman parameters, such as full width at half maximum (FWHM) of the D1 and G bands, and XRD parameters, including d002 and crystallite sizes Lc and La, showed that the solid bitumens of the Paja Formation have a low structural order equivalent to high-rank coals, specifically anthracites B (3.0% ≤ Ro < 4.0%), although their reflectance values placed them in a higher rank (Ro > 4.0%). The discrepancy between high reflectance and low degree of structural order can explain why some of the equations used to estimate equivalent vitrinite reflectance (Ro eq. Vite) from solid bitumens do not work universally. Taking in consideration several equations available in the literature, Jacob's equation (Jacob, 1989) was the one that fitted the Ro eq. Vite values in the range of 3.0% to 4.0%, which parallels with the degree of structural order obtained for the solid bitumens. Consequently, Jacob's equation can now be extended to solid bitumen in the range of cata-impsonites.

Backtracking to Parent Maceral from Produced Bitumen with Raman Spectroscopy

In order to assess a source rock for economical exploitation purposes, many parameters should be considered; regarding the geochemical aspects, the most important ones are the amount of organic matter (OM) and its quality. Quality refers to the thermal maturity level and the type of OM from which it was formed. The origin of the OM affects the ability of the deposited OM between sediments to generate oil, gas, or both with particular potential after going through thermal maturation. Vitrinite reflectance and programmed pyrolysis (for instance, Rock-Eval) are common methods for evaluating the thermal maturity of the OM and its potential to generate petroleum, but they do not provide us with answers to what extent solid bitumen is oil-prone or gas-prone, as they are bulk geochemical methods. In the present study, Raman spectroscopy (RS), as a powerful tool for studying carbonaceous materials and organic matter, was conducted on shale and coal samples and their individual macerals to show the potential of this technique in kerogen typing and to reveal the parent maceral of the examined bitumen. The proposed methodology, by exhibiting the chemical structure of different organic matters as a major secondary product in unconventional reservoirs, can also detect the behavior of solid bitumen and its hydrocarbon production potential for more accurate petroleum system evaluation.

Influence of Pore Structure and Solid Bitumen on the Development of Deep Carbonate Gas Reservoirs: A Case Study of the Longwangmiao Reservoir in Gaoshiti–Longnusi Area, Sichuan Basin, SW China

A variable sedimentary environment and accumulation process leads to a complex pore structure in deep carbonate gas reservoirs, and the physical properties are quite different between layers. Moreover, some pores and throats are filled with solid bitumen (SB), which not only interferes with reservoir analysis, but also affects efficient development. However, previous studies on SB mainly focused on the accumulation process and reservoir analysis, and there are few reports about the influence on development. In this paper, through scanning electron microscope analysis, SB extraction, gas flow experiments and depletion experiments, and a similar transformation between experimental results and reservoir production, the production characteristics of carbonate gas reservoirs with different pore structures were studied, and the influence of SB on pore structure, reservoir analysis and development were systematically analyzed. The results show that permeability is one of the key factors affecting gas production rate and recovery, and the production is mainly contributed by high-permeability layers. Although the reserves are abundant, the gas production rate and recovery of layers with a low permeability are relatively low. The SB reduces the pore and throat radius, resulting in porosity and permeability being decreased by 4.73–6.28% and 36.02–3.70%, respectively. With the increase in original permeability, the permeability loss rate decreases. During development, the loss rate of gas production rate is much higher than that of permeability. Increasing the production pressure difference is conducive to reducing the influence. SB also reduces the recovery, which leads to the loss rate of gas production being much higher than that of porosity. For reservoirs with a high permeability, the loss rates of gas production rate and the amount produced are close to those of permeability and porosity. Therefore, in the reservoir analysis and development of carbonate gas reservoirs bearing SB, it is necessary and significant to analyze the influence of reservoir types.