Solid Bitumen Research Articles

Occurrence morphology of bitumen in Dengying Formation deep and ultra-deep carbonate reservoirs of the Sichuan Basin and its indicating significance to oil and gas reservoirs

Abundant bitumen can be discovered in the wells of Upper Sinian Dengying Formation in the Sichuan Basin and their peripheral outcrops sections. As the cracking product of a paleo-oil reservoir, the occurrence morphologies and distribution characteristics of bitumen in carbonate reservoirs can indicate the preservation, migration and other key information of (paleo-) oil and gas reservoirs. In order to provide reference and basis for the deep and ultra-deep oil and gas exploration in the Sichuan Basin and the basins in western China, this paper systematically studies the occurrence morphological characteristics of bitumen in deep and ultra-deep carbonate reservoirs in well Gaoshi 1 of the Sichuan Basin by carrying out thin section observation, scanning electron microscope-energy spectrum analysis and fluid inclusion organic geochemical analysis on the cores of the fourth member of Dengying Formation (Deng 4 Member). In addition, the coupling relationship between the occurrence morphology of bitumen and the key event of hydrocarbon accumulation is revealed. And the following research results are obtained. First, solid bitumen in the Deng 4 Member deep and ultra-deep reservoir has two types of occurrence morphology. The first type of bitumen adheres to pore walls in the shape of a rim or exists in pores in the form of sticky branch (e.g., Wells Chuanshen 1 and Gaoshi 1). There are more obvious shrinkage fractures and residual pores generated by in-situ thermal cracking in this type of bitumen. And combined with fluid inclusion and burial thermal history, it can effectively indicate that a paleo-gas reservoir has been preserved so far since the paleo-oil reservoir was thermally cracked into carbonaceous bitumen. The second type of bitumen is distributed in intra- and inter-neogenic mineral crystals in pores disorderly in the shape of grain and band (e.g., Wells Mashen 1 and Wutan 1) and it has obvious breaking edges. It reveals that after a paleo-oil reservoir was thermally cracked into carbonaceous bitumen, the paleo-gas reservoir suffered blowdown and gas escape and neogenic fluid minerals moved into reservoirs to fill in pores. In conclusion, the occurrence morphologies and distribution characteristics of bitumen in deep and ultra-deep carbonate reservoirs can effectively indicate the hydrocarbon accumulation and evolution process of paleo-oil and gas reservoirs.

Molecular mechanisms of solid bitumen and vitrinite reflectance suppression explored using hydrous pyrolysis of artificial source rock

The most commonly used parameter for thermal maturity calibration in basin modelling is mean random vitrinite reflectance (Ro). However, Ro suppression has been noted in samples containing a high proportion of liptinite macerals. This phenomenon has been demonstrated empirically using hydrous pyrolysis of artificial source rock containing various proportions of thermally immature Wyodak-Anderson coal and liptinite-rich kerogen from the Parachute Creek Member of the Green River Formation. Analysis of samples pyrolyzed at 330 °C for 72 h demonstrates that Ro values of both vitrinite and solid bitumen are suppressed in rocks containing liptinite-rich kerogen. Raman and micro-Fourier transform infrared (µ-FTIR) analyses were performed to investigate the mechanisms of suppression. Raman maturity proxies show decreased aromaticity in samples with suppressed Ro, particularly in solid bitumen, with aromaticity decreasing as the proportion of liptinite increases. The µ-FTIR proxy for aliphatic chain length and/or branching ratio is static in solid bitumen, yet increases slightly in vitrinite as the liptinite proportion increases. These spectroscopic results suggest slightly different suppression mechanisms for vitrinite and solid bitumen, with reduced CC bond cleavage and marginally reduced aromaticity in vitrinite with suppressed Ro, and strongly reduced aromaticity and CC bond cleavage in solid bitumen with suppressed Ro. These results support the hypothesis that the generation of free radicals during maturation slows aromatization and highlight the disadvantages of using solid bitumen Ro for maturity calibration in liptinite-rich samples. Furthermore, our results indicate that use of Raman data obtained from liptinite-rich samples may also result in suppressed maturity indicators, particularly if the macerals are not identified prior to analysis.

Study on the logging response characteristics and the quantitative identification method of solid bitumen at different thermal evolution stages

Solid bitumen is the intermediate products during the oil and gas generation, and widely exists in petroliferous basins all over the world. Besides damaging the reservoir physical properties, solid bitumen affects the logging parameters and is hard to be identified by the conventional logging method. In this study, two different thermal evolution stages of solid bitumen, separately from the Devonian outcrop profile and the Well ST3 in the northwestern Sichuan Basin, are taken as an example. Through a series of analyses on the porosity, permeability, resistivity, S-wave time difference, P-wave time difference and nuclear magnetic resonance (NMR) before and after bitumen dissolution, the logging response characteristics of solid bitumen at different thermal evolution stages are clarified, and the logging quantitative identification method of solid bitumen is established. The results are as below: (1) The solubility of solid bitumen is linearly correlated with the increment of porosity, permeability, P-wave time difference and S-wave time difference, and exponentially correlated with the decrement of resistivity. (2) Under the equal solid bitumen content and with the increase of thermal evolution, the influence of solid bitumen on porosity and permeability gradually decreases, while the influence on acoustic time difference and resistivity gradually increases. (3) Two kinds of NMR logging interpretation models for bitumen reservoir are established based on the NMR response characteristics of solid bitumen at different thermal evolution stages. The solid bitumen from low thermal evolution stage has a strong response in NMR, while that from high thermal evolution stage is otherwise. The Peak 1 (0.1 ms – 10 ms) of the T2 spectrum can respond to most of the low thermal evolution stage solid bitumen, but just a few of the high thermal evolution stage solid bitumen. (4) The NMR logging quantitative calculation methods on different thermal evolution stage solid bitumen are established respectively to solve the difficult issues of quantitative identification of solid bitumen. All the researches above have important guiding significance for the logging quantitative calculation of solid bitumen and the selection of effective oil/gas test layers.

Maturation and migration processes in intact source rock micro plugs induced by chemical and thermal treatment: A new approach combining Rock-Eval pyrolysis and organic petrography

This study proposes a new approach to investigate hydrocarbon generation and migration processes in petroleum source rocks under laboratory conditions. For the first time, programmed open-system pyrolysis using a Rock-Eval 6 instrument is applied on small, polished source rock plugs to induce changes in the type and distribution of solid bitumen, which are qualitatively investigated by means of organic petrography before and after different pyrolysis experiments. This approach allows us to directly visualize the evidence of solid bitumen (SB) formation and distribution after the following treatments: (1) thermal extraction at 300 °C for 3 min, (2) chemical extraction of the surface using dichloromethane (DCM), and subsequently (3) artificial maturation by applying the standard procedure of Rock-Eval programmed pyrolysis up to a temperature of about 400 to 500 °C (depending on the initial thermal maturity of the sample). After each step, the surface of the treated micro plugs was digitally scanned to allow a comparison of specific areas of interest before and after the respective treatments and alterations. For this study, core samples of the Eagle Ford Shale Formation are used, which are suitable for such investigation, as the Eagle Ford Shale exhibits a variety of different initial thermal maturities from immature to overmature. Furthermore, the presence of large intraparticle porosities provides suitable voids where changes in SB distribution can easily be observed. After the thermal extraction, the volume of observed SB in the early- and moderately mature samples slightly increased, while most of the thermally mobilized bitumen from inside the plug was evaporated and thus lost from the sample. The initial solid bitumen was not or hardly affected by thermal extraction at 300 °C for 3 min, i.e. it was thermally stable at this temperature. Solid bitumen reflectance was slightly higher than in the initial sample showing a minor maturation. In contrast to thermal extraction, solid bitumen in the early mature samples was almost completely dissolved after DCM treatment. These petrographic observations on micro plugs are in agreement with the pyrolysis results of powdered fractions, where the initial Rock-Eval S1 and to a much lesser extent also the S2 signal decreases after the chemical extraction in DCM. While the SB in early mature sample was almost entirely dissolved by DCM, only about half of it is was dissolved in the moderately mature sample showing more mature and more stable SB. After the artificial maturation, the volume of SB in early- as well as in moderately mature samples clearly increased within the intraparticle pores, indicating presence of new SB due to bitumen migration from the deeper part of the micro plug to the surface. In contrast, SB in initially overmature sample is mainly present as thermally-highly stable pyrobitumen, indicated by no change in the SB distribution after chemical and thermal treatments representing a stable type of SB at the very end of petroleum generation.

Controls of marine shale gas accumulation in the eastern periphery of the Sichuan Basin, South China

This study examines the mechanisms that most influenced the accumulation of shale gas deposits of the Lower Cambrian Niutitang, Upper Ordovician Wufeng, and Lower Silurian Longmaxi formations of the eastern periphery of the Sichuan Basin. Abundant organic matter (OM) (2.0–5.0 wt%), appropriate thermal maturity (solid bitumen reflectance = 2.5–3.5%), and favorable kerogen types highlight the especially excellent hydrocarbon generation potential of the lower member of the Niutitang Formation and the Wufeng Formation. The development of pores hosted by OM particles and the presence of authigenic quartz account for the elevated porosity (3–5%) of these deposits and their adsorption capacity in the range of 1.5–2.5 m3/t. Strong top and base seals and a pressure coefficient (ratio of reservoir pressure to hydrostatic column pressure) greater than 1.4 of Wufeng Formation shale favor gas preservation in these deposits. However, poor associated sealing lithologies, an excessively high uplift amplitude (> 6900 m), and low pressure coefficient (< 1.0) account for diminished gas preservation in the lower member of Niutitang Formation. The low OM abundance and porosity of the upper member of Niutitang Formation and the Longmaxi Formation are more suggestive of a cap rock than a source or reservoir rock.

Characterization of bituminite in Kimmeridge Clay by confocal laser scanning and atomic force microscopy

This work investigates bituminite (amorphous sedimentary organic matter) in Upper Jurassic Kimmeridge Clay source rock via confocal laser scanning microscopy (CLSM) and atomic force microscopy (AFM). These petrographic tools were used to provide better understanding of the nature of bituminite, which has been historically difficult to identify and differentiate from similar organic matter types in source rocks. As part of an International Committee for Coal and Organic Petrology (ICCP) working group, an immature (0.42% vitrinite reflectance), organic-rich (44.1 wt% total organic carbon content) sample of Kimmeridge Clay was distributed to multiple laboratories for CLSM characterization. The primary observations from CLSM imaging and spectroscopy include: 1) the interpreted presence of Botryococcus algae as a contributor to bituminite precursors; 2) color red-shift of sulfide reflectance and bituminite auto-fluorescence from below the sample surface; 3) positive alteration of bituminite from laser-induced photo-oxidation of the sample surface, including fluorescence blue-shift; 4) fluorescence blue-shift associated to higher fluorescence intensity regions in bituminite indicative of compositional (fluorophore) differences; 5) the need for fluorescence spectroscopy standardization as applied via CLSM; and 6) the suitability of CLSM fluorescence spectroscopy to predict solid bitumen reflectance from bituminite spectral emission via calibration to an extant dataset. Secondary CLSM observations include detection of reflected laser light from highly reflective inclusions in bituminite, including sulfides and fusinite, and radiolytic alteration of bituminite caused by substitution of U for Fe in sulfides. Findings from AFM include the observation that surface roughening or surface flattening of bituminite are induced by differential broad ion beam (BIB) milling and are dependent on the location and scale of AFM topology measurement. This result highlights our still limited understanding of the effects of BIB milling on sedimentary organic matter and indicates the need for further research before this technique can be advanced as a standard practice in petrographic sample preparation. Collectively, the results of this study illustrate the general applicability and versatility of AFM and CLSM as tools for organic petrology research, specifically for better understanding of the nature and properties of the bituminite maceral.

Heterogeneous distribution and potential significance of solid bitumen in paleo-oil reservoirs: Evidence from oil cracking experiments and geological observations

The solid bitumen (SB) residing in reservoirs after oil cracking can reduce reservoir quality. To build a quantitative standard for the SB content for paleo-oil reservoir identification and to evaluate the heterogeneous distribution of SB and its effect on reservoir quality, we conducted a cracking experiment on eight dolostone samples injected with oil and analyzed the SB content (vol%) and porosity of 706 reservoir samples from the Sichuan Basin that had undergone oil cracking. The SB contents of the experimental samples (0.95–1.48 %) injected with normal oil were higher than those of the experimental samples (0.22–0.49 %) injected with light oil. Furthermore, for the experimental samples injected with the same type of oil, the SB contents of the samples with higher paleoporosities (PPs) were also higher than those of the samples with lower PPs. For the reservoir samples from the Sichuan Basin, the SB content exhibits a generally positive correlation with PP. When the PP was <2.5 %, the SB content was relatively low (<1.0 %); and when the PP was >2.5 %, the SB content increased significantly and was generally > 1.0 %. The data obtained from the oil cracking experiments and reservoir samples from the Sichuan Basin suggests that SB contents of 1.0 % and 0.4 % can be used as the lower limits for normal and light oil reservoir identification, respectively. The oil cracking experiments verified that SB preferentially resided in the smaller pores and throats, and the SB saturations of the samples with lower PPs were larger than those of the samples with higher PPs. For the reservoir samples from the Sichuan Basin, a paleo-oil reservoir with a PP > 8.0 % can be an effective gas reservoir, but some of the paleo-oil reservoirs with PPs of 2.5 %–8.0 % are ineffective gas reservoirs due to SB filling. As a result, the heterogeneous distribution of SB should be carefully considered in gas reservoir evaluation.

In-situ SEM characteristics of dispersed organic matter in continental shale with its implication for dessert evaluation--A case study of Paleogene shale in the Cangdong Sag, Bohai Bay Basin, China

Organic matter (OM) in continental shale serves as both the source of oil and gas and the storage space in unconventional petroleum systems. However, directly identifying the types of organic matter under SEM is challenging when simultaneously observing minerals and pores. Kong2 Member(E2k2) of Paleogene in Cangdong sag of Bohai Bay basin is a typical continental shale oil layer in China. Based on the positioning observation technology combining field emission scanning electron microscope (FE-SEM) and fluorescence microscope, the in-situ SEM identification and observation of macerals were carried out, and the identification methods and characteristics of organic macerals were summarized. The results show that: (1) Organic macerals in E2k2 shale are divided into vitrinite, inertinite, liptinite and solid bitumen by external morphology, hardness, brightness, color, protrusion, pore and fracture development of organic matter, and further subdivided into multiple subcategories. Based on the SEM charging effect of the remaining oil, it is further confirmed that the shale movable oil and oil generation potential developed by lipoid group is the largest, while the shale movable oil and oil generation potential developed by vitrinite group and inertinite group is the worst; (2) The organic pores include primary pores and secondary pores. The pores of primary organic matter are derived from the biological structure of primary organic matter, and the secondary organic pores are developed during the thermal maturation of oily organic matter. Clay mineral catalysis, difference of hydrocarbon generation potential and residual pores of primary organic matter control the development of organic pores; (3) Calcareous-dolomitic shale and felsic shale are typical lithology formed in relatively dry and humid climate respectively, and the types of organic macerals are significantly different. Although the former has weak total hydrocarbon generation, it has stronger oil generation potential and is worthy of attention in dessert prediction and exploration.

The effect of paleo-environment on hydrocarbon generation potential: Example from Vaca Muerta Formation, Neuquén Basin, Argentina

A 137-m continuous core from the Jurassic-Early Cretaceous marine derived oil shale with the maturity Ro about 0.7 %, representing the oil window in the Vaca Muerta Formation, Neuquén Basin, Argentina, was examined using geological, mineralogical, petrographic, and geochemistry techniques. Three distinct intervals were identified within the core: the upper carbonate-rich section with intense bioturbation, indicating dysoxic to oxic conditions that resulted in poor organic matter preservation; a middle section with decreasing carbonate content, suboxic bottom conditions, and higher organic matter content; and a lower section with higher detrital input and low carbonate content, suboxic to anoxic water conditions, and enhanced preservation of organic matter. Based on the presence of indicator fossils and geochemical parameters, a general trend of increasing organic matter content with lower paleo-oxygen levels was observed. The proportion of solid bitumen within organic matter increases with decreasing oxygen content, suggesting that organic matter deposited in anoxic conditions is more prone to transformation and hydrocarbon generation. There is a negative impact of increasing paleo-oxygen levels on the quantity and quality of organic matter, represented by its potential to generate hydrocarbons.

Reservoir solid bitumen-source rock correlation using the trace and rare earth elements–implications for identifying the natural gas source of the Ediacaran-Lower Cambrian reservoirs, central Sichuan Basin

The hydrocarbon-source correlation in highly-mature and over-mature stages is a challenging task in natural gas exploration. The Ediacaran-Lower Cambrian natural gas in the central Sichuan Basin is typical oil-cracking gas. With a burial depth of more than 4650 m, the gas is now in the highly-mature to the over-mature stage (equivalent Ro>1.8%) with apparent alteration by thermochemical sulfate reduction (TSR), leading to difficulties for gas-source correlation. Conventional hydrocarbon-source correlation mainly relies on organic geochemical methods, taking media such as biomarkers and carbon isotope for correlation. However, in the highly-mature and over-mature stages, the characteristics of conventional biomarkers tend to be homogenised. Furthermore, the gas components and carbon isotope of natural gas are frequently altered by TSR in the deep burial stage. Thus, conventional organic geochemical methods are significantly restricted. This paper explored the source of highly-mature natural gas from the DY and LWM Formations in the central Sichuan Basin by studying the inorganic geochemical information (trace elements and rare earth elements) of the reservoir bitumen and potential source rocks. The results show that the depositional environment of the potential source rocks (the QZS and the D-3 source rocks) in the central Sichuan Basin were different. The redox-sensitive parameters (V/(V + Ni), Mo/Ni, δCe and Ce/Y) and the provenance-sensitive parameters (La/Co and La/Sc) of the source rocks have apparent differences, which can be used as the basis for gas-source correlation. The correlation results show that the LWM gas was derived from the QZS source rock, while the D-2 and D-4 gases were mainly derived from the QZS source rock, with a partial contribution of the D-3 source rock. During geologic evolution, the crude oil generated from the two sets of source rocks were thoroughly mixed in the paleo-oil reservoir of the D-4 Member. As a result, the characteristics of the D-3 source rock were obscured by the QZS. In contrast, the solid bitumen in the D-2 paleo-oil-reservoir recorded the contribution of the D-3 source rock. However, this contribution was limited within the range of 50 m adjacent to the D-3 Member by a more significant oil generation from the QZS source rock located in Deyang-Anyue Rift Trough. This study clarified the gas source differences between the D-2 Member, D-4 Member and LWM Formation, providing a new insight for in-depth study on the gas accumulation of the Ediacaran-Lower Cambrian in the central Sichuan Basin.

STRATIGRAPHIC CORRELATION AND SOURCE ROCK CHARACTERISTICS OF THE BALUTI FORMATION FROM SELECTED WELLS IN THE ZAGROS FOLD BELT, KURDISTAN REGION, NORTHERN IRAQ

The Upper Triassic Baluti Formation has been identified and mapped based on its log response in selected wells from the Zagros foldbelt in the Kurdistan Region of northern Iraq. A preliminary evaluation of the formation's source rock potential was made by Rock‐Eval screening analysis in four wells along a NW‐SE profile (Atrush‐1, Shaikan‐5B, Taq Taq‐22 and Miran‐2) with maturity determined from reflectance measurements in samples from well Taq Taq‐22. The Baluti Formation consists of thinly interbedded shales, carbonates and anhydrite ranging in thickness from 48 m in well Atrush‐1 to 118 m in well Miran‐2. The Rock‐Eval screening was conducted primarily on bulk cuttings samples plus selected picked cuttings. The TOC content is low to moderate (0.23 to 1.14 wt%). However, the shale content in many of the analysed bulk samples was relatively low, making assessment of the source potential problematic. The highest TOCs are recorded from the thickest analysed sections from wells Miran‐2 and Taq Taq‐22, where high‐gamma bituminous shales are present. Rock‐Eval Tmax values ranging from 295 to 438°C are not consistent with estimates of pre‐Zagros burial to depths of between 4600 m (Atrush‐1) and 6900 m (Miran‐2). The relatively low Tmax values suggest that the S2 response does not reflect kerogen pyrolysis in these samples and may be due to the presence of solid bitumen, which is observed in the Baluti Formation in at least three of the study wells (Taq Taq‐22, Miran‐2 and Shaikan‐5B). Little pyrolysable organic matter remains in the formation due to the interpreted deep pre‐Zagros burial and the consequent high maturity in Taq Taq‐22 (VR = 1.51%Ro) and Miran‐2 (estimated VR &gt;2%Ro), and the poor source character in Atrush‐1 and Shaikan‐5B. Organic petrography suggests the presence of vestiges of Types I and II kerogen in Taq Taq‐22, with bitumen observed as stains in the matrix of the shales and also in the pores and fractures of interbedded dolostones. However, bitumen reflectance determinations for Taq Taq‐22 indicate an equivalent vitrinite reflectance maturity of no more than 0.93%Ro, which is significantly less than that of the indigenous vitrinite, implying the solid bitumen in this well is derived primarily from migrated hydrocarbons. Further detailed analysis is required, but the results suggest that the Baluti Formation may have sourced hydrocarbons in its depocentre which is identified in this study as covering a NW‐SE trending area between Bekhme and Sangaw.

Organic Petrology and Thermal Maturity of Dispersed Organic Matter from the Ramalhal-1 Well (Lusitanian Basin, Portugal)

Organic petrology is an important tool used to characterize dispersed organic matter (DOM) in sediments and sedimentary rocks, and to assess its thermal maturity. This study was carried out on 33 cutting samples (Middle-Upper Jurassic) from the Ramalhal-1 well to characterize the particulate organic matter and to evaluate its thermal maturity. The samples were submitted to optical petrography analysis (reflected white and blue incident lights) and the mean random reflectance was measured. Microscopic observations revealed a low DOM content, characterized by the predominance of macerals of the inertinite group (including charcoal), followed by solid bitumen. Huminite/vitrinite is usually small in size and quantity. Liptinite macerals were also present, represented by sporinite, cutinite, liptodetrinite and rare bituminite. A type III-IV kerogen was defined for the Ramalhal-1 sequence. Huminite/vitrinite mean random reflectance varied between 0.38% and 0.75%, pointing to an immature-to-mature stage of the organic matter. Multi-populations of solid bitumen occurred in almost all the samples, filling voids and fractures in the inorganic materials (mainly carbonates). The bitumen populations were quite heterogeneous, concerning both the optical characteristics and distribution, displaying different thermal maturities. No relationship between vitrinite and bitumen reflectance was established, indicating that these bitumens were not generated in situ.

Discovery of an extraordinary Carboniferous cutinite-rich coal seam from Wadi Abu Thora, southern Sinai, Egypt: Organic petrographical and geochemical characterization

An extraordinary cutinite-rich coal seam from the Abu Thora Formation in the Wadi Abu Thora area, west central Sinai, Egypt, was studied in detail. A sample taken from the seam consisted almost of pure cutinite with minor sporinite (megaspores) and secretinite, along with solid bitumen veins and exsudatinite. The cutinite-producing cuticles appear to have single plant origin as indicated by their morphological features and geochemistry. The cuticles display yellow fluorescence under under blue light illumination and were arranged in bands that present the ability to trace a single cuticle for the full length of the sample. The detrital component present between the cuticle bands was minimal. Organic geochemical analysis by Rock-Eval pyrolysis revealed a S2 of 214.2 mg/g rock and a hydrogen index of 477 mg HC/g TOC, which point to liptinite-rich kerogen Type II. Pyrolysis gas chromatography showed a well-defined chromatogram with abundant compounds in the range between C11 and C21. Organic matter in the coal seam is in the early mature stage based on cutinite fluorescence color, the Tmax of 437 °C, and the solid bitumen reflectance (0.30%), which equates to % vitrinite Ro of 0.60. Inorganic geochemical analysis revealed a low concentration of trace elements and deposition in swamp conditions without any influence by marine waters. Transmission FTIR analysis revealed spectra typical of cutinite, marked by a strong peak at 1710–1700 cm−1 attributed to the fatty acids CO group. The cutinite was produced by xerophytic pteridosperm plants as indicated by the chemotaxonomic correlation based on FTIR analysis. These plants produced larger quantities of cutinite relative to other maceral components, such as vitrinite or sporinite because of their relatively high frond biomass. Pinnule-bearing fronds that fell off the plants and accumulated in the flooded swamp were removed quickly from acrotelm to catotelm by rapid subsidence, where they were eventually preserved intact and with little alteration by microorganisms.

Solid Bitumen Occurrences in the Pyrenean Basin (Southern France): A Case Study across the Pliensbachian–Toarcian Boundary

The study across the Pliensbachian–Toarcian boundary sedimentary record in the Bizanet section of the Pyrenean Basin (southern France) revealed the presence of solid bitumen. This secondary organic matter was characterized using petrographic (transmitted and reflected white lights, incident blue light, and scanning electron microscopy) and geochemical (total organic carbon, total sulfur, and insoluble residue) techniques. The spore coloration index (SCI) was also determined. With the characterization of the optical properties and reflectance of the solid bitumen, it was possible to distinguish four different families (A–D) that display a wide range of reflectance values, from 0.21% to 2.64% BRr, i.e., from glance pitch to meso-impsonite. SCI values were higher than 9–9.5 (%Req &gt; 1.50%). The comparison between the equivalent vitrinite reflectance values of the solid bitumen and SCI showed that this index and the solid bitumen D values are concordant, indicating that solid bitumen D can be considered an indigenous bitumen. The other three families of solid bitumen (A–C) are considered as having migrated. The laterally equivalent Pont de Suert section (South Pyrenean Zone) displays no trace of solid bitumen which points to the important role of the morphotectonic context of the Bizanet section in the migration of these hydrocarbons, namely, the presence of a major thrust fault in the eastern Corbières close to the section’s location.

Petrophysical properties of a siltstone reservoir - An example from the Montney Formation, western Canada

The detrital grain size of siltstone reservoirs occupies a middle ground between sandstones and shales, both of which are better understood in terms of their petrophysical properties. Because siltstones can be important hydrocarbon reservoirs, we examine controls on petrophysical properties in the Lower Triassic Montney Formation in western Canada, which hosts world-class reserves of gas, gas liquids and oil. We focus on the effects of rock fabric (including grain size) and composition on pore system characteristics and permeability, drawing contrasts between the three reservoir types.The Montney Formation is an unconventional reservoir through most of its subcrop, with porosities ranging from ∼3 to 7.5% and permeabilities in the micro to nano Darcy range (6.5*10−6 mD to 5.6*10−2 mD). Shale reservoirs worldwide are characterized by similar porosity and permeability values, with porosity of up to 8% (rarely up to 15%) and permeability in the nano to micro-Darcy range.Quartz, clay, and organic matter abundance influence the petrophysical properties of the Montney siltstone. Quartz content exerts a positive control on both porosity and permeability by strengthening the rock framework and reducing porosity loss due to compaction. Elevated clay content is also associated with higher porosity and permeability, in part because of a depositional association with quartz, and in part because clays locally shelter interconnected primary porosity that promotes permeability. Organic matter content is negatively correlated to porosity and permeability despite the presence of organic matter porosity because relict oil (now solid bitumen) occludes primary pores and because other pore types contribute a greater fraction of the total pore volume. Lithofacies, characterized in four cores, are indistinguishable on the basis of petrophysical properties, due to their similar grain size and composition and the massive overprinting by shallow burial diagenesis.While the pore system evolution of sandstones is mainly controlled by the mechanical compaction of hard grains and cementation, pore system evolution of shales is primarily controlled by compaction of ductile grains and diagenesis of primary organic matter, in addition to cementation. Porosity and permeability values of the Montney siltstones are similar to those of shale formations, but the controls on pore system evolution of this intermediate grain size reservoir are predominantly controlled by processes similar to sandstones: compaction, cementation, and cement dissolution. Minor contribution from secondary porosity in bitumen affects some sections of the reservoir in a way that is similar, but not identical, to shale reservoirs.

Hydrocarbon potential and Organofacies of the Devonian Antrim Shale, Michigan Basin

The Devonian Antrim Shale is an unconventional biogenic gas accumulation with a technical recoverable resource of 19.9 Tcf. However, major knowledge gaps remain regarding understanding of the source rock potential, organic facies assemblages and paleo-depositional conditions of the Antrim Shale members. This work utilized Rock-Eval pyrolysis, reflected light microscopy and solid bitumen reflectance to characterize the source rock quality, organo-facies assemblages, and thermal maturity of the various Antrim Shale members at three different localities in the Michigan Basin. Results showed that the Lachine and Norwood members are richer in organic matter (up to 24 wt%) than the Upper and Paxton members (<8 wt%). Organic matter is mainly dominated by marine Type II kerogen in the black shales of the Lachine and Norwood members, and by Type II and Type II/III in the Paxton Member. Telalginite, which is represented mainly by Tasmanites and Leiosphaeridia cysts, is the dominant organic matter in the black shale members where they account for about two-thirds of the organic matter composition. Solid bitumen, which accounts for less than one-third of the organic matter composition, is second after alginite. Both alginite and solid bitumen populations decline in abundance progressively in the Upper and Paxton members at the expense of inertinite and vitrinite. The dominant organofacies groups in the studied Antrim Shale members can be assigned to the BP type B and type D/E. Organic matter maturity determined from Rock-Eval Tmax and bitumen reflectance varies from immature to marginally mature across the Michigan Basin. The results confirmed that sediment burial depth and lateral position in the basin controlled organic facies assemblages within the Antrim Shale members.

Differential impact of clay minerals and organic matter on pore structure and its fractal characteristics of marine and continental shales in China

Clay minerals and organic matter are commonly developed in shale sediments, and have an important influence on the pore structure and pore complexity of shale reservoirs. However, due to the complexity of shale pore structure and the diversity of influencing factors, the influence of organic matter, clay minerals and organo-clay composites on shale pore structure is still unclear. In this study, the effects of organic matter, clay minerals and organo-clay composites on pore structure and pore complexity of marine Longmaxi shale (LMX shale) and continental Ziliujing shale (ZLJ shale) were investigated qualitatively and quantitatively by field emission scanning electron microscopy (FE-SEM), N2 adsorption experiment with Frenkel-Halsey-Hill (FHH) model. The results comprehensively reveal the differential effect of organic matter and clay minerals, the most important pore-forming materials in shale, on the pore development of shale reservoir. Overall, the maceral type, maturity, illite, kaolinite and organo-clay composites are the main controlling factors for shale pore development and complexity. More specifically, maceral type and maturity have great influence on shale pore structure and pore complexity of all shale samples, while the effect of organic matter abundance could be ignored in continental shale. Solid bitumen is prone to develop secondary organic pores, while other macerals such as vitrinite and inertinite do not develop secondary pores with the increase of maturity. In the high-over mature marine LMX shale, a large number of secondary organic pores are generated after solid bitumen cracking and gas generation, which promotes the pore complexity. In the low-mature continental ZLJ shale, the solid bitumen has not reached the maturity of cracking gas, and the original bioclastic pores do not develop, leading to the weak development of organic pores and small contribution to pore complexity. Different clay mineral types have different effects on shale pore structure and pore complexity. The shale pore volume (PV) and specific surface area (SSA) increase with the increase of illite content, and the existence of illite enhances pore surface roughness and pore heterogeneity. However, the effect of kaolinite content on shale pore structure and pore complexity is completely opposite to that of illite. The formation of organo-clay composites protects the primary pores, and promotes the hydrocarbon generation and pore development of organic matter, which greatly increases the development of shale pores. The outcomes of this studies would provide better understanding on the pore formation mechanism of shale reservoir, which is of great significance for the accurate assessment of shale gas resources.

Origin and Genesis of Solid Bitumen from the Sinian Dengying Reservoir in the Deyang–Anyue Rift within the Sichuan Basin (SW China): Evidence from Biomarkers and Microscopic Features

Deep-carbonate gas reservoirs are a significant field for conventional gas exploration in the Sichuan Basin, and industrial-grade gas reservoirs have recently been discovered in the second member of the Dengying Formation in the Deyang–Anyue rift. Drilling results have indicated that the large amount of solid bitumen that is commonly found in pores and fractures in the reservoir of the second member of the Dengying Formation. However, systematic studies have not yet been conducted on the solid bitumen of the second member of the Dengying Formation and its genesis and parent source remain unclear. This study is based on the systematic analysis of solid bitumen samples collected from new exploratory wells, with the aid of optical microscopy, scanning electron microscopy, and gas chromatography–mass spectrometry to clarify the genesis, thermal maturity, and parent source deposition environment of the solid bitumen. Electron microscopy and biomarker results indicate that bitumen is in a high-maturity stage and is a product of the thermal cracking of crude oil. Energy dispersive spectrometer results and the continuous distribution of n-alkanes indicate that the bitumen is not subjected to strong thermochemical sulfate reduction and biodegradation. Isoprenoids and terpenes suggest that the palaeoreserves associated with the bitumen of the second member of the Dengying Formation originate in reductive marine carbonate sediments. The combination of regional stratigraphic contact relationships, lithology, and biomarker characteristics implies that the Maidiping Formation muddy dolomite and the Dengying Formation algal dolomite are the potential parent sources of solid bitumen in the second member of the Dengying Formation.

Organic pore heterogeneity and its formation mechanisms: Insights from the Lower Cretaceous lacustrine Shahezi shale in the Songliao Basin, NE China

Pores associated with organic matter are well known to play a significant role in shale gas capacities. However, an extremely high heterogeneity of organic pores often impacts our evaluation of reservoir quality. In this work, we analyze the formation mechanisms of the heterogeneity based on positioning observation method using a combination of field emission scanning electron microscopy and optical microscopy. These analyses were conducted on six lacustrine shale samples at the gas window in the Lower Cretaceous Shahezi shale, which is located in the Changling Fault Depression of Songliao Basin. The results reveal that organic pore heterogeneity is mainly attributed to four controlling factors. (a) One is different hydrocarbon generation potentials among different macerals. The degree of pore development from high to low is solid bitumen, vitrinite, and inertinite. The content of carbon by the weight percentage of solid bitumen, vitrinite, and inertinite is in the opposite order, which reflects that the different hydrocarbon generation potential of each maceral is the dominant factor. (b) Another one is the remnants of primary pores in organic matter with plant cell structures. Well preserved telinite, fusinite, and semi-fusinite show cell structures, and the cells that are not completely compressed or not fully filled retain the original residual pores. (c) The third one is evolutional differences of individual solid bitumen. Not all solid bitumen developed organic pores, which is mainly attributed to the difference of solid bitumen reflectance in different solid bitumen particles. The solid bitumen reflectance of porous solid bitumen is mostly distributed between 1.6% and 2.0%, in which oil cracking to gas is dominant and porous residual solid bitumen subsequently forms. The solid bitumen reflectance of non-porous solid bitumen peaks in 1.2–1.6%, which is in the stage of kerogen transformation and oil generation with rare pore development. (d) The last one is the catalysis of clay minerals. All organoclay complexes develop abundant sponge-like pores due to catalysis during the transformation from smectite to illite. A high content of illite in the mixed layers I/S increases the specific catalytic activities, promoting the organic matter and solid bitumen to further generate hydrocarbon and form pores. Most organic–inorganic mixtures develop pores also because of catalysis from inorganic minerals.

Factors influencing the evolution of shale pores in enclosed and semi-enclosed thermal simulation experiments, Permian Lucaogou Formation, Santanghu Basin, China

The microscopic pore structure of organic-rich shales is an important factor affecting the enrichment of shale gas; however, the characteristics of pore structure changes during thermal evolution are unclear, and the factors influencing the pore evolution remain controversial. High-temperature and high-pressure semi-enclosed and enclosed pyrolysis experiments were conducted in the low-mature oil shale of the Middle Permian Lucaogou Formation in the Santanghu Basin, Xinjiang, to reveal the evolution characteristics of shale pores from the low-mature to high- and over-mature stages. The results show that in the low-mature to mature stages, retained oil/residual bitumen has a clogging effect on shale pores in both systems, and the extra pressure destroys the structure of the mesopores and macropores. However, in mature to high- and over-mature stages, the pore pressure generated by the cracking of oil and gas transforms some micropores to mesopores and macropores in both systems. In semi-closed systems, large amounts of pre-oil and hydrocarbons are discharged periodically, which is conducive to the development of kerogen pores; however, the pore contents of solid bitumen and pyrobitumen are relatively small. In other cases, organic pores in solid bitumen and pyrobitumen in enclosed systems are more developed.