Black Shale Samples Research Articles

Petrophysical and geochemical characterization of potential unconventional gas shale reservoirs in the southern Karoo Basin, South Africa

Ten Permian black shale samples from the southern Karoo Basin (South Africa) were investigated regarding their shale gas generation potential, storage capacity and transport properties. Samples originate from a 671 m deep borehole (KZF-1), comprising the Collingham, Whitehill and Prince Albert Formations of the lower Ecca Group (Karoo Supergroup).Based on organic geochemical analyses (TOC, TS, Rock-Eval pyrolysis and vitrinite reflectance), the Whitehill Formation was deposited under anoxic marine depositional conditions and has reached high thermal maturity. The Collingham and Prince Albert Formation were deposited under suboxic to oxic conditions. The amount of total organic carbon (TOC) across all formations ranges between 0.5 and 6.1 wt.-%, and was highest for the Whitehill Formation samples. The organic matter in the different lithologies are highly overmature with vitrinite reflectance values around 4.0% VRr, and almost absent Rock-Eval S1 and S2 peaks. Peak gas generation probably occurred due to tectono-metamorphic overprinting during the Cape Orogeny (240–270 Ma).Permeability ranges from 10−22 to 10−19 m2 (1–100 nDarcy) and is lowest for the Whitehill and Prince Albert Formation. Porosity at ambient stress ranges from 4.1 to 6.3% and is highest within the Whitehill Formation. Neither permeability nor porosity show significant dependence upon induced stress. Excess sorption capacity is highest for the Whitehill Formation, nexcess10MPa ranging from 0.079 to 0.172 mmol/g. For the depth interval investigated here (671 m), the estimated total gas storage capacity (sum of free and adsorbed gas phase) of the Whitehill Formation is approximately 400 to 465 mol CH4 per m3 rock. Using a simple one-dimensional diffusion model, we calculated the potentially remaining stored amount of gas. In a modelled best-case scenario, it is assumed that dissipation of the gas only occurs through the side boundaries (fractured dykes system) whereas top and bottom are assumed to act as perfect seals. Assuming a fracture distance of 1000 m, the model predicts complete gas dissipation to take place within a period of 10−2 to 102 Ma. Regarding the peak gas generation at 240–270 Ma, the remaining shale gas potential is therefore considered extremely low.

Middle Miocene Black Shale of Airbenakat Formation in Berau Areas, Jambi: are they potential source rock?

The research location is geologically located in Jambi Sub-basin composed by Peneta Formation (KJp), Airbenakat (Tma), and Muara Enim (Tmpm). Specifically this research focuses on the physical characteristics and geochemistry of Middle Miocene black shale from Airbenakat Formation. The purpose of this research is to determine whether the black shale of this formation has the potential as a source rock. The method of this research are field observation that includes the description of rock samples and geological mapping, and laboratory analysis including rock geochemical analysis. Three samples were taken from black and fine-grained shale. Total organic carbon (TOC) values of the three samples taken ranged from 0.38-0.42%, the weight of TOC indicates a potentially close enough to produce hydrocarbons. the pyrolysis results show that the S1 data gives a value below 0.5 HC/g and S2 gives a value below 2.5 HC/g, so it can be seen that the three rock samples that tested are not sufficient enough to produce hydrocarbons. Overall the sample has a S2/S3 ratio ranging from 0.09-0.23 and Tmax-HI data has values ranging from 8-19 mg HC/g TOC, so it can be seen that the ratio S2/S3 less than 1 and the value of the index hydrogen below 50 mg HC/g TOC, It can be concluded that the samples are derived from type IV kerogen. The maximum temperature (Tmax) of pyrolysis shows a value of less than 4350C, where the values range from 350-4280C. So, it can be interpreted that the three samples are immature source rocks because the catagenesis phase to produce hydrocarbons has not been achieved. The conclusions is the three samples of black shale tested indicate potential as immature source rock and has the close enough ability to produce hydrocarbons. The result of the analysis then comparable with the result analysis of Airbenakat Formation Black Shale in Palembang Sub-basin which has fair-well ability to produce hydrocarbons.

Geomechanical characterization of gondwana shale across nano-micro-meso scales

We study multiphase and multiscale mechanical properties of the Gondwana shale samples obtained from the Raniganj Formation of central and eastern India. The mechanical properties of black and gray shale samples cored perpendicular to the bedding plane direction are analyzed across nano-to-micro scales using the nanoindentation method. We characterize the multiphase structure of the two shales in terms of three mechanical phases–quartz/feldspar/pyrite, organic matter, and kaolinite–and use that to explain the heterogeneous elastoplastic behavior observed during nanoindentation. We quantify the fracture toughness of black and gray shales at microscale using our modified energy method, which relates the energy released during a pop-in event to a radial fracture model. We extend the deconvolution approach over multiple properties to estimate the uncertainty in multiphase structure and phase volume fractions. We used the viscosity-toughness scaling analysis to study the difference in hydraulic fracturing behavior of the black and gray shales. We show the influence of nano- and micro-scale multiphase mineralogical properties on characteristic length, time and pressure scales of fracture propagation at mesoscale.

Quantitative comparison of microfabric and magnetic fabric in black shales from the Appalachian plateau (western Pennsylvania, U.S.A.)

Anisotropy of magnetic susceptibility (AMS) has been shown to be a good proxy for crystallographic preferred orientation (texture). However, it is not clear in detail how different factors, e.g. modal composition and preferred orientation, define the total AMS in a rock. Black shale samples from a drill core on the Appalachian Plateau in western Pennsylvania were analyzed with respect to their microfabric as determined by texture and microstructure, and AMS. Low- and high-field AMS, which was measured at room temperature, reveals that the AMS of the samples is dominated by the para- and diamagnetic phases. Synchrotron diffraction was applied to determine the texture of all relevant mineral phases incorporated in the samples. Muscovite and chlorite pole figures show single maxima perpendicular to the foliation, reflecting dominant flattening strain. From these textures and the modal compositions, AMS models were calculated using the intrinsic magnetic anisotropy of the single crystals. The modeled and measured AMS are comparable in terms of their principal directions and shapes of the anisotropy ellipsoid for the dominantly paramagnetic samples, with the maximum susceptibility axes oriented subhorizontal to the NE-SW. Both, textures and AMS, indicate that the samples have undergone largely bedding compaction with a weak tectonic overprint linked to the Alleghenian orogeny. Our results suggest that the microfabric and the magnetic fabrics on the plateau, 200 km away from the Allegheny Front, detect the tectonic shortening. The AMS modeling demonstrates how the contribution of the intrinsic AMS of each mineral controls the AMS of the whole rock.

Hydrocarbon Potential of the Triassic Lacustrine Source Rocks in the Newark Basin, USA

This study investigates the hydrocarbon potential of the organic matter-rich Triassic rocks of the Newark basin in the USA. The development of anoxic conditions during the Late Triassic led to the accumulation and preservation of the organic matter during the deposition of the Lockatong formation in a lacustrine setting. The total organic carbon (TOC) values of the black shale samples from the Nursery and Titusville cores of this formation range from 0.50 to 2.72% (avg.=1.2%), indicating a fair to good source rock. On the Hydrogen Index (HI) vs the Oxygen Index (OI) diagram, the studied samples plot at the end of the evolutionary paths of kerogen types I, II, and III. This indicates that the organic matter is overmature and is in the dry gas window. This degree of maturity is also consistent with the Tmax values ranging from 506°C to 547°C and is confirmed by published vitrinite reflectance values (%Ro) which vary between 1.95 and 2.69%. This overmaturity is the result of an active subsidence during the Late Triassic-early Jurassic in relation with the reactivation with the deep-seated regional NE-SW-trending faults. Although the overmaturity of the organic matter renders the identification of the type of organic matter difficult, the organic matter is likely kerogen II-III type. On the basis of the available data, it is concluded that this formation has no generative liquid hydrocarbon potential.

Geochemical Characterization of Exposed Black Shale Sediments of Matamuhari Anticline, Bangladesh

Matamuhari anticline is one of the largest anticline situated at Bandarban district of Bangladesh which is 60 km long and 20 km wide in the part of Bangladesh. Like other part of Bangladesh the whole sequence of exposed rocks of Matamuhari anticline is composed with Neogene sedimentary rocks of shale, sandstone, siltstone, silty shale, tabular and spheroidal calcareous concretions. Seven outcrop black shale samples were collected during February 2013 from the different parts of the anticline namely Boro Bari Jhiri, Ochir Jhiri and Tak Chara area were mineralogically and geochemically examined in order to better understand the depositional environment in the studied area. The major and trace elements were analyzed using XRF spectrometry. Two distinct lithofacies assemblages, mud and silty-clay are found in the collected sediments. The shales are predominated by quartz, kaolinite, chlorite, mica (muscovite and biotite), feldspar (both K-feldspar and plagioclase), and in addition to a variable ratio of vermiculite. Lithologial characteristics and geochemical data demonstrated that sediments are enriched with TOC contents ranging from 0.39 to 0.67 wt.% and shows distinctive correlation to concentration of TOC and particle size distribution. These shales are characterized by a low Mg and K as well as high Al and Fe contents. Studies also show that the values of MgO/Al2O3 and K2O/Al2O3 ratio ranges from 0.15 to 0.17 and 0.18 to 0.20 respectively. The relationship of log MgO/Al2O3 and log K2O/Al2O3 values reveals that all of the studied samples fell within the marine environment. Ni/Co ratio of the studied shale samples ranges from 2.84 to 3.88 (average 3.36). These low values of Ni/Co ratio suggest that the sediments were deposited under oxic conditions. However, the above observations suggest that the sediments of Matamuhari anticline area were deposited in a shallow marine environment under oxic conditions.

Geochemical features and genetic mechanism of deep-water source rocks in the Senegal basin, West Africa

This paper discusses the maturity of source rocks of the Senegal basin through basin simulation, so as to get a better understanding of oil-source correlation. Based on the analysis of pyrolysis chromatography and total organic carbon (TOC) data of core samples taken from 11 wells, the model of Cenomanian-Turonian marine sediment-organic facies was established, and the genetic mechanism of high-quality source rocks was clarified. The results show that source rocks in the Senegal Basin may occur in the Aptian-Albian of Lower Cretaceous and Cenomanian-Turonian of Upper Cretaceous. One is hybrid organic facies in the shallow carbonate platforms in the shelf area and is characterized by moderate to high TOC (<3%) and hidrogen index ? HI, (100-400 mg HC/g). The other is well-preserved marine facies in continental slope to abyssal sea, with high TOC (>3%) and high HI (max 900 mg HC/g TOC). Molecular fossils originating from aryl carotene are the indicator of the existence of euphotic zone in the ancient ocean. The compounds of aryl isoprenes and sulfurous aryl isoprenes are detected in the black shale samples of well DSDP 367. They rooted in photosynthetic green sulfur bacteria and the carbon isotope value of these compounds is higher 10?~15? than those of fossil molecules of algae and cyanobacteria. Two packages of oil-prone source rocks separately occurr in the Aptian-Albian of Lower Cretaceous and Cenomanian-Turonian of Upper Cretaceous. High-graded marine source rocks of the Senegal Basin may occur in a sulfurous, anoxic deep-water environment with sufficient carbon sequestration.

Organic petrography and petroleum source rock evaluation of the Cretaceous Mamfe Formation, Mamfe basin, southwest Cameroon

The Mamfe basin is thought to be a rift splay segment of the southern Benue Trough and is genetically link to the Abakaliki and Anambra sub-basins in Nigeria. In the Mamfe basin very little studies have been done on maceral characterization and hydrocarbon generative potential of the Cretaceous black shale. Organic petrography and Rock–Eval pyrolysis studies were done on the black shale outcropping in the basin. The objectives were to determine the types of macerals present, and their relative abundance as well as their hydrocarbon generation potential; to assess the black shale's source rocks richness and quality; and to evaluate the source rock thermal maturity and the relationship between maturity and hydrocarbon generation. The results of this investigation indicated that the maceral content include relatively low percentages of vitrinite (4.9%), inertinite (3.4%) and scare liptinite (0.5%). The total organic carbon of the samples vary from 0.17 to 4.53 wt%, (mean = 1.11 wt%) indicating poor to good source rocks generative potential while the S1 values ranges from 0.04–1.25 mg HC/g rock, (mean = 0.23 mg HC/g rock), indicating poor–fair source rocks generation potential. Most of the samples are mature-peak mature for gaseous hydrocarbon generation. Based on the organic petrography and geochemical analyses performed on the black shale samples of the Mamfe Formation, they are described as mainly humic type III-reworked/oxidized type IV kerogen. The genetic potential of these source rocks is low and free hydrocarbon are absent. Given the prevalence of type III/IV kerogen, thermal maturity levels and hydrocarbon yield, it can be concluded that the source rocks of the Mamfe Formation have some moderate to fair potential for gaseous hydrocarbon which have not yet been generated at the present outcrop levels.

Shale facies from the Wufeng-Lower Longmaxi Formations in the Huangying section of Wulong County, southeastern Sichuan Basin, China

With the increasing interest on shale oil and shale gas around the world, it is essential to discover alternative economic shale gas fields outside the Fuling gas field, which is China’s first large-scale shale gas field with 100 billion cubic meters of reserves in the Sichuan Basin (China). Based on comprehensive analysis of dozens of black shale samples, the Wufeng Formation and the Lower Longmaxi Formation in the Huangying section of Wulong County showed good prospects for shale gas. An integrated study of petrology, organic geochemistry, trace element analysis, and sedimentology reveals that the sea level during the Early Silurian period was relatively high. Consequently, carbon-rich and high-silica lithofacies were deposited, corresponding to argillaceous-siliceous deepwater shelf microfacies. During deposition of the Guanyinqiao bed (latest Ordovician), the sea level was relatively low, resulting in the formation of moderately high carbon and high-silica shale facies, corresponding to argillaceous shallow shelf microfacies. A complete transgressive-regressive third-order sequence was recorded in the Longmaxi Formation. Carbon-rich and high-silica lithofacies, which are associated with carbonaceous deepwater shelf microfacies and siliceous-argillaceous deepwater shelf microfacies, respectively, dominated the transgressive system tract. Compared with the Fuling area with a record of high shale gas productivity, the Wufeng Formation and the transgressive system tract of the Longmaxi Formation in the study area demonstrate great potential for shale gas.

Source-rock evaluation and depositional environment of black shales in the Triassic Yanchang Formation, southern Ordos Basin, north-central China

A recent drilling operation in the Triassic Yanchang Formation (Tongchuan District of the Ordos Basin, north-central China) reached a black shale bed with an average in-situ gas content of 1.11 g/ml. Subsequent total organic carbon (TOC) content measurements and rock-eval analysis showed that the black shale section was generally classified as excellent source rock, with TOC contents commonly over 12% and an average genetic potential reaching 90 mg HC/g rock. The black shale samples of the Yanchang Formation contain kerogen of types I and II1, indicating the presence of oil source rocks, and the Tmax values range from 438 to 442 °C, which indicate a maturity stage in the early oil window. To reconstruct the depositional environment of the black shales with high TOC contents, various geochemical elements and their ratios were analyzed, yielding a number of interesting results: (i) the paleoclimate indexes CIA, CIW and C-values range from 50 to 72 (mean 65), 56 to 85 (mean 75), and 0.8 to 2.6 (mean 1.5), respectively, indicating humid conditions during the sedimentation period of the black shales; (ii) the redox conditions during the sedimentation of the black shales were dysoxic to anoxic as evidenced by the cross-plot of V/Cr vs. V/(V + Ni); (iii) the water column environment was a deep, fresh-water lake, further confirming the moist paleoclimate and reducing environment; and (iv) the high TOC contents of the black shales are attributed to inputs from hydrothermal fluids as evidenced by the samples falling into or near to the hydrothermal area of the Ni/Cr vs. Ti plot and the Ti vs. V plot.

Nickel isotopic variation in black shales from Bohemia, China, Canada, and Finland: a reconnaissance study

We present δ60Ni values for black shales, determined by double-spike MC-ICP-MS. The samples comprise Paleoproterozoic Talvivaara Ni–Zn–Co–Cu black shales from Finland, Neoproterozoic black shales from the Tepla-Barrandian Unit, Czech Republic, Early Cambrian Ni–Mo-rich black shales from the Yangtze Craton, and Devonian Ni–Zn–PGE black shales from Yukon, Canada. In addition, the sample set includes a black smoker sample from the Logatchev hydrothermal field, Mid-Atlantic Ridge. The δ60Ni values vary from − 0.84 ± 0.09 to + 0.62 ± 0.04‰ (2SD) with a median of − 0.10‰ (n = 28). Ni isotopic compositions were predominantly lighter than those of abiotic terrestrial and extraterrestrial samples (0.15 and 0.27‰), mantle (0.23‰, Gall et al. 2017), present-day seawater (1.44‰, Cameron and Vance 2014), dissolved Ni from riverine input (0.84‰, Cameron and Vance 2014), ferromanganese crusts (0.9–2.5‰, Gall et al. 2013), Devonian/Mississippian organic-rich marine sediments, lower Jurassic organic-rich marine sediments (0.2–2.5‰, average 0.92‰, n = 18, Porter et al. 2014), and euxinic sediments of the Black Sea (0.14–0.51‰, Vance et al. 2016). However, the range of δ60Ni values in our black shale samples was close to that of the weathering products of mafic/ultramafic rocks (ore and soil samples) ranging from − 0.60 to + 0.30‰ (Ratie et al. 2015; Spivak-Birndorf et al. 2018), Ni-sulfide ores hosted by Archean komatiites from Australia and Canada (− 0.10 to − 1.03‰, average − 0.70‰, n = 8, Gueguen et al. 2013), and Archean Ni-rich magmatic sulfides from Zimbabwe (− 0.28 to − 0.47‰, n = 6, Hoffman et al. 2014). Based on our observations and considering the extremely low contribution of direct biological uptake of Ni, and a dominant Ni residence in early Fe/Ni-sulfides, we suggest that our mostly light Ni isotopic compositions in metal-rich black shales result from sulfidization of organic matter and Ni removal into sulfides.

Characterization of organic carbon in black shales of the Kachchh basin, Gujarat, India

Thirty-three black shale samples from four locations on the onland Kachchh basin, western India were analyzed to characterize organic carbon (OC), thermal maturity and to determine the hydrocarbon potential of the basin. Upper Jurassic black shales from the Jhuran Formation (Dhonsa and Kodki areas) are characterized by the presence of chlorite, halloysite, high \(T_{\mathrm{max}}\), low OC, low hydrogen index and high oxygen index. These parameters indicate the OC as type IV kerogen, formed in a marine environment. The rocks attained thermal maturity possibly during Deccan volcanism. Early Eocene samples of the Naredi Formation (Naliya-Narayan Sarovar Road (NNSR) and the Matanomadh areas) are rich in TOC, smectite, chlorite and framboidal pyrite, but have low \(T_{\mathrm{max}}\). These indicate deposition of sediments in a reducing condition, probably in a lagoonal/marsh/swamp environment. Organic carbon of the Naredi Formation of NNSR may be considered as immature type III to IV kerogen, prone to generate coal. Core samples from the Naredi Formation of the Matanomadh area show two fold distribution in terms of kerogen. Organic carbon of the upper section is immature type III to IV kerogen, but the lower section has type II to III kerogen having potential to generate oil and gas after attaining appropriate thermal maturity.

Microtomographic analysis of controlling parameters on permeability and elastic velocities of black shales

Shales are sedimentary rocks characterized by their very fine grain size, and are basically composed of clays and silts. Important features of shales are their fissility, presenting thin layers almost always parallel to their bedding, low permeability and elastic velocities which can vary significantly, but whose controlling factors are not yet well understood. X-ray microtomography (microCT) is a widely-used technique to reconstruct the internal pore space of rocks and other materials. In this work parameters controlling permeability and elastic velocities of black shales are investigated through x-ray microCT digital image analysis. Results show that black shale permeability is controlled mainly by pore size distribution and pore connectivity, while elastic velocities of such rock type are controlled by porosity, pore size and the quality of grain–grain contacts. Mineral composition of the analyzed rock samples does not affect this analysis since all the samples have similar mineral content. MicroCT images show clearly the predominant pore locations along the fissility planes, which is a determinant factor in the difference between elastic velocities of horizontal and vertical rock samples. The macropores of the analyzed rock samples are not well interconnected, in contrast with the micropores, which present high pore connectivity and capillary pressure. A quality index for grain–grain contacts is proposed here which is the dominant factor controlling the elastic velocities of the analyzed black shale samples, followed by macro and micro porosities. Vertical samples, whose elastic velocities are lower than those of horizontal ones, present low values for the quality index of grain–grain contacts.

Surface properties of neutral components in copper column bioleaching of black shale samples

Surface properties of neutral components in copper column bioleaching of black shale samples

Preliminary view of geotechnical properties of soft rocks of Semanggol formation at Pokok Sena, Kedah

The research was inspired by series of geological studies on Semanggol formation found exposed at North Perak, South Kedah and North Kedah. The chert unit comprised interbedded chert-shale rocks are the main lithologies sampled in a small-scale outcrop of Pokok Sena area. Black shale materials were also observed associated with these sedimentary rocks. The well-known characteristics of shale that may swell when absorb water and leave shrinkage when dried make the formation weaker when load is applied on it. The presence of organic materials may worsen the condition apart from the other factors such as the history of geological processes and depositional environment. Thus, this research is important to find the preliminary relations of the geotechnical properties of soft rocks and the geological reasoning behind it. Series of basic soil tests and 1-D compression tests were carried out to obtain the soil parameters. The results obtained gave some preliminary insight to mechanical behaviour of these two samples. The black shale and weathered interbedded chert-shale were classified as sandy-clayey-SILT and clayey-silty-SAND respectively. The range of specific gravity of black shale and interbedded chert/shale 2.3 – 2.6 and fall in the common range of shale and chert specific gravity value. In terms of degree of plasticity, the interbedded chert/shale samples exhibit higher plastic degree compared to the black shale samples. Results from oedometer tests showed that black shale samples had higher overburden pressure (Pc) throughout its lifetime compare to weathered interbedded chert-shale, however the compression index (Cc) of black shale were 0.15 – 0.185 which was higher than that found in interbedded chert-shale. The geotechnical properties of these two samples were explained in correlation with their provenance and their history of geological processes involved which predominantly dictated the mechanical behaviour of these two samples.

Organic geochemistry of the Middle-Upper Jurassic Naokelekan Formation in the Ajil and Balad oil fields, northern Iraq

Sixteen organic-rich argillaceous limestone and black shale samples from three wells with up to 16 wt% TOC (average 9.32 wt%) from the Middle–Upper Jurassic Naokelekan Formation in the west Zagros Basin of northern Iraq were evaluated as source rocks. Both organic geochemical and molecular data indicate an open marine environment at the time of deposition, leading to accumulation of Type-II and Type-III kerogen with varying oil and gas generation potential. The predominance of short-chain n-alkanes (n-C13–n-C19), and C27 and C29 steranes, and absence of oleanane confirm the dominantly planktonic/bacterial and algal origin of the organic matter. Organic richness, low Pr/Ph, and high C35/C34 homohopane ratios suggest alternating anoxic to suboxic depositional conditions. Biomarker distributions are consistent with sporadic anoxia, with unequivocal evidence for stratification of the water column and hypersalinity. The 22S/(22S + 22R) ratios for C32 homohopanes, moretane/hopane, and C29 sterane 20S/(20S + 20R) and ββ/(ββ+αα) ratios vary irregularly, whereas the C27 diasteranes, Ts/(Tm + Ts), triaromatic cracking and MDR ratios vary substantially and increase with burial depth among different homologues within the same sample set, indicating the threshold to peak of the oil-generation window. Based on hierarchical cluster analysis (HCA) and principal component analysis (PCA) of 13 selected source-related biomarker ratios, the source rock extracts have been divided into three groups: Group-1 from the Ba-1 well, Balad oil field, and Groups-2 and -3 from the Aj-8 and Aj-12 wells, respectively, in the Ajil oil field.

A laboratory study of geomechanical characteristics of black shales after sub-critical/super-critical CO2 + brine saturation

This paper presents an experimental study of the impact of CO2–brine–rock interaction on the mechanical properties of shales. Several black shale samples were soaked in sub-critical/super-critical dissolved brine solutions with different adsorption time. Uniaxial compressive strength (UCS) tests together with the AE and SEM technology are used to test the variations of shale’s mechanical properties, crack propagations and microstructures. According to the experimental results, CO2–brine–rock interaction has a great effect on shale’s strength, Young’s modulus and brittleness index which decrease with increasing saturation time. With a 30 days’ adsorption, the UCS and Young’s modulus show large reductions of 60.56 and 52.68% for sub-critical condition and 70.47 and 62.45% for super-critical condition, respectively. AE analysis presents that the total cumulative AE energy increases dramatically after adsorption. Longer saturation time creates more AE energy. Super-critical condition has a higher effect on shale’s mechanical values and acoustic emission energy than the sub-critical condition. Some new micron scale pores appear on SEM images after saturation. Based on the EDS analysis, CO2–brine–rock interaction also causes the increase of C, Na and Fe contents, and the decrease of O, Si, Al and K contents, which prove the occurrence of the dissolution and precipitation.

Geochemical characteristics of the Paleogene-Neogene coals and black shales from Malaysia: Implications for their origin and hydrocarbon potential

Paleogene-Neogene coals are widespread in Malaysia, cover a wide age spectrum and are considered the source rock of hydrocarbons in Malaysia. However, they have not been studied systematically up to now. Moreover, the black shales associated with these coals were not taken into consideration in previous studies. Therefore, this study presents systematic inorganic and Rock-Eval analyses of the Paleogene-Neogene coals and their associated black shales to examine their origin, depositional environment and hydrocarbon potential.With the exception of coals from the Tanjong Formation, Sabah, the Paleogene-Neogene coals are characterized by very low ash yields and low concentrations of trace and rare earth elements including hazardous trace elements. The black shales are composed of quartz, illite, kaolinite and traces of pyrite in some samples. Al2O3/TiO2 ratios in the coals (6–62) and black shales (16–34) suggest a mixture of felsic and intermediate igneous rocks as sources for their detrital fractions, which is supported by the Zr-Ti binary plot. V/(V+Ni) ratios average between 0.8 and 0.7, V/Ni between 13.5 and 3, and Ni/Co between 1.7 and 3.8 for coal and black shale samples; respectively, indicating suboxic to anoxic depositional conditions for both groups of samples. Rock-Eval analysis indicates that coal and black shale samples contain mixed Type II–III kerogens, which suggest similar organic input from terrestrial high plants. The samples also contain immature to mature organic matter and can produce gas and oil. These characteristics along with the high TOC contents (very good to excellent) indicate that the Paleogene-Neogene coals and black shales are potential source rocks for oil and gas fields in Malaysia. The coals and black shales from different ages and localities were shown to have similar source area composition, climate conditions during their deposition, terrestrial organic input as well as suboxic to anoxic depositional conditions. However, coals and black shales from the early-middle Miocene Tanjong Formation exhibit higher Al2O3/SiO2 ratios than the rest of coals and black shales suggesting a prevalence of wetter climatic conditions during formation. In addition, coals and black shales from the early-middle Miocene Tanjong Formation and upper Pliocene Liang Formation show higher values for redox proxies such as V/(V+Ni), V/Ni, Ni/Co and Ce* compared with other formations, indicating the dominance of reducing conditions during the deposition of these formations.

Effects of slick water fracturing fluid on pore structure and adsorption characteristics of shale reservoir rocks

The shale-fracturing fluid interaction and its effects on the pore structures and adsorption characteristics of shale are the key factors affecting shale gas exploration. To address this problem, the black shale samples obtained from the Lower Silurian Longmaxi Formation in Sichuan Basin, China were exposed to slick water fracturing fluid at the simulation conditions of 100 °C and 50 MPa for 72 h through a fluid-rock interaction simulation instrument. The slick water fracturing fluid contained 0.2 wt.% friction reducer, 1 wt.% clay control agent, 0.15 wt.% cleanup agent and 0.05 wt.% demulsifier. The mineral composition, pore structure and methane adsorption capacity of shale samples before and after slick water fracturing fluid treatment were measured by X-ray diffraction (XRD), field emission scanning electron microscope (FE-SEM), low-pressure nitrogen adsorption and methane isothermal adsorption experiments using the gravimetric method. The results showed that the carbonate minerals were dissolved during treatment, and as a result, the samples developed many dissolution pores measuring 2–5 μm in diameter, while the other minerals remained relatively undisturbed. The specific surface area and total pore volume of shale sample were reduced after the reaction, and the shale-fracturing fluid interaction exhibited a stronger influence on the mesopores. However, the average pore diameter of nanopore was enlarged after the reaction, increasing from 4.29 nm to 4.78 nm. The changes of fractal dimensions suggested an increase in the roughness of pore surfaces, and the pore structure became more regular. The methane adsorption capacity in shale treated with fracturing fluid was reduced from 1.23 mmol/g to 0.95 mmol/g. The changes in the pore structure and adsorption characteristics of shale could affect the gas flow and gas adsorption capacity. These results indicated that the slick water fracturing fluid may play an important role in shale matrix stimulation.

Adsorption of pure CO2 and a CO2/CH4 mixture on a black shale sample: Manometry and microcalorimetry measurements

The study of CO2/CH4 adsorption onto kerogen is relevant for shale gas production. Despite much expanded literature, reliable adsorption models still await for a complete description due to the complexity of kerogen. The objective of this study is to provide an original set of experimental data and to use the selectivity as an indicator to test the affinity of the sample for a component over another. The adsorption of pure CO2 and the equimolar mixture CH4/CO2 were explored on a Silurian black shale sample. This outcropping sample was collected in a formation, which is not considered as target for shale gas exploration. However its geochemical profile as well as its thermal maturity suggest this sample is an ideal candidate to study kerogen/carbon dioxide and methane interactions. Both isotherm and enthalpy of adsorption of carbon dioxide were measured up to 3.2 (MPa) by the use of a combined manometric-calorimetric device. The carbon dioxide isotherm was fitted with a modified Langmuir model allowing the determination of the adsorption uptake. The heat of adsorption is an indicator of the affinity of the carbon dioxide with kerogen. Additionally the equimolar mixture methane/carbon dioxide isotherm was performed up to 2 (MPa) by use of a device specially developed and built for gas mixture co-adsorption. The adsorption of each component within the mixture was provided. The estimated selectivity CO2/CH4 highlights a significant affinity of CO2 with the kerogen.