Organic-rich Shale Units Research Articles

Well-logging evaluation of the shale gas potential in the lower Silurian Longmaxi Formation, Weiyuan, southern Sichuan Basin, China

Recent observations of shale gas breakthroughs in the Weiyuan marine shale gas play in the Sichuan Basin have attracted great interest. To better understand these breakthroughs, we have used core description, cyro-focused ion beam scanning electron microscopy data, X-ray diffraction data, organic geochemistry, and well-logging data to better understand the reservoir characteristics carbonaceous shale, calcareous shale, and siliceous shale lithology, with a focus on organic-rich shale units. We find that conventional well-log methods are effective in mapping the spatial distribution of organic-rich shale in the Weiyuan area where the total organic carbon (TOC) content in the Longmaxi Formation ranges from 1.35% to 6.95%, averaging 4.42%. The kerogen is type I-II, and the vitrinite reflectance (Ro) is greater than 2.57%, which indicates that the formation is susceptible to shale gas accumulation. The clay mineral content ranges from 48 to 63 wt% (avg. 51 wt%) with illite and chlorite averaging 73.8% and 25.7%, respectively. The brittle mineral quartz and plagioclase content ranges from 32 to 61 wt% (avg. 47 wt%). Compared to the surrounding lithologic units, the marine shale exhibits relatively high gamma ray, neutron, sonic, resistivity, potassium, and uranium (U) values and relatively low density, photoelectric effect, and thorium/U values, allowing us to construct crossplots to define the units of interest. Using the same process, we quantify the TOC content providing a spatial distribution of organic-rich shale using conventional well logging.

Oil migration, retention, and differential accumulation in “sandwiched” lacustrine shale oil systems from the Chang 7 member of the Upper Triassic Yanchang Formation, Ordos Basin, China

To extract hydrocarbons from unconventional shale systems, it is necessary to assess oil retention and accumulation. This study presents experimental findings on oil retention, migration, and accumulation in a lacustrine shale system from the Chang 7 member of the Upper Triassic Yanchang Formation, Ordos Basin. 68 core samples were collected from the target layer to investigate the migration behavior of trapped hydrocarbons by organic geochemical, petrological, and petrophysical methods. The amount of oil retention and generation potential was determined using total organic carbon and programmed pyrolysis analysis. The pore structure and pore connectivity were quantified using scanning electron microscopy and micro-computed tomography scanning. Shale samples were also fractionated to determine the chemical composition of extracted hydrocarbons using a ternary azeotropic solvent extraction system. The effects of lithofacies, mineral compositions, organic matter, and pore structure on oil retention and accumulation were studied based on these findings.The findings revealed that lithofacies have a significant impact on the composition and amount of oil stored in the “sandwiched” shale systems. As oil is sorbed by organic matter, organic-rich shale lithofacies retain a large amount of oil. However, due to the developed dissolution-related pores in feldspar, the interbedded organic-lean siltstones have a higher oil saturation index and contain more free oil. Pore diameters and pore connectivity are also larger in the thin organic-lean siltstones. Shale oil intrasource migration and charging are observed in the Chang 7 member lithofacies assemblages during primary migration: oil is generated in organic-rich source rocks and expelled in short distances to adjacent siltstones. The thin organic-lean siltstones act as reservoir units for petroleum that has migrated from organic-rich shale units. Simultaneously, oil in thin siltstone intervals enriches in aliphatic and aromatic compounds, while petroleum from source rocks enriched in asphaltenes and resins, due to migration fractionation. This research shows oil migration and differential accumulation in the “sandwiched” shale systems in the Chang 7 member of the Upper Triassic Yanchang Formation, enhancing our knowledge of shale oil accumulation.

Re–Os age for the Lower–Middle Pennsylvanian Boundary and comparison with associated palynoflora

The Betsie Shale Member is a relatively thick and continuous unit that serves as a marker bed across the central Appalachian basin, in part because it includes an organic-rich shale unit at its base that is observable in drill logs. Deposited during a marine transgression, the Betsie Shale Member has been correlated to units in both Wales and Germany and has been proposed to mark the boundary between the Lower and Middle Pennsylvanian Series within North America. This investigation assigns a new Re–Os date to the base of the Betsie and examines the palynoflora and maceral composition of the underlying Matewan coal bed in the context of that date. The Matewan coal bed contains abundant lycopsid tree spores along its base with assemblage diversity and inertinite content increasing upsection, as sulfur content and ash yield decrease. Taken together, these palynologic and organic petrographic results suggest a submerged paleomire that transitioned to an exposed peat surface. Notably, separating the lower and upper benches of the Matewan is a parting with very high sulfur content (28wt.%), perhaps representing an early marine pulse prior to the full on transgression responsible for depositing the Betsie. Results from Re–Os geochronology date the base of the Betsie at 323±7.8Ma, consistent with previously determined age constraints as well as the palynoflora assemblage presented herein. The Betsie Shale Member is also highly enriched in Re (ranging from 319.7 to 1213ng/g), with high 187Re/188Os values ranging from 3644 to 5737 likely resultant from varying redox conditions between the pore water and overlying water column during deposition and early condensing of the section.

Source potential of the upper Jurassic rocks of the Barents Sea petroleum basin

A preliminary assessment of the source potential of the Jurassic section was obtained using organic geochemical data on samples collected from outcrops on Franz Josef Land and Svalbard archipelagoes as well as boreholes in the Barents Sea basin. The presence of organic-rich shale units with good source potential was reported for the first time within the studied section of Early to Middle Jurassic age, along with well-documented Upper Jurassic source rocks. The study provides an assessment of regional variations in the kerogen type, hydrocarbon generation potential, and maturation of organic matter from Jurassic sediments.

Organic-rich shale in the Palaeoproterozoic Kajrahat Formation, Vindhyan Supergroup, Son Valley: implications and genesis

The paper attempts to interpret the textural attributes of the shelf-originated, organic-rich shale unit of the Kajrahat Formation in the Proterozoic Vindhyan Supergroup. The black shales, alternating with thinly laminated dolomite beds exhibit many textural features, indirectly indicating microbial mat growth on muddy siliciclastics. The microbial mat features are subdivided broadly into three different categories related to growth, destruction and diagenesis of microbial mat. Wavy and crinkly laminated fabric is very characteristic of the shales, thin mud drapes imparting the wavy laminae conspicuous. Pyrite, formed because of anaerobic decay of microbial mat follows the carbonaceous laminae, rather than being disseminated. Cohesive behaviour of the shales is manifested by the folded and contorted nature of the carbonaceous laminae at places. Sticky nature of the microbial mats possibly generated the quartz-silt aggregates and abundant scattered quartz silts within the carbonaceous laminae. The black shale unit of the Kajrahat Formation, thus, appears to have microbial mat origin like many other contemporaneous black shales reported from Precambrian black shales. The occurrence of microbially originated, organic-rich shale suggests curtailment of siliciclastic supply.

Stratigraphy, sedimentology and bulk organic geochemistry of black shales from the Proterozoic Vindhyan Supergroup (central India)

Four organic-rich shale units of the Proterozoic Vindhyan sedimentary succession have been scanned to reveal their origin and hydrocarbon potential. The wavy-crinkly nature of the carbonaceous laminae is suggestive of a microbial mat origin of the shales. These shales are thus different from Phanerozoic black shales which typically exhibit planar laminae. The hydrocarbon potential of the black shale units has been evaluated by Rock-Eval pyrolysis. Total organic carbon content of many of the shales exceeds 1%. The meanT max for the black shales translate to a vitrinite reflectance range of 2.05-2.40% Rm based on standard conversion techniques. These shales have reached the catagenetic stage near the beginning of anthracite formation.

Lower Silurian `hot shales' in North Africa and Arabia: regional distribution and depositional model

Lowermost Silurian organic-rich (`hot') shales are the origin of 80–90% of Palaeozoic sourced hydrocarbons in North Africa and also played a major role in petroleum generation on the Arabian Peninsula. In most cases, the shales were deposited directly above upper Ordovician (peri-) glacial sandstones during the initial early Silurian transgression that was a result of the melting of the late Ordovician icecap. Deposition of the main organic-rich shale unit in the North African/Arabian region was restricted to the earliest Silurian Rhuddanian stage ( acuminatus, atavus and probably early cyphus graptolite biozones). During this short period (1–2 m.y.), a favourable combination of factors existed which led to the development of exceptionally strong oxygen-deficiency in the area. In most countries of the study area, the post-Rhuddanian Silurian shales are organically lean and have not contributed to petroleum generation. The distribution and thickness of the basal Silurian `hot' shales have been mapped in detail for the whole North African region, using logs from some 300 exploration wells in Libya, Tunisia, Algeria and Morocco. In addition, all relevant, accessible published and unpublished surface and subsurface data of the lower Silurian shales in North Africa and Arabia have been reviewed, including sedimentological, biostratigraphic and organic geochemical data. The lowermost Silurian hot shales of northern Gondwana are laterally discontinuous and their distribution and thickness were controlled by the early Silurian palaeorelief which was shaped mainly by glacial processes of the late Ordovician ice age and by Pan-African and Infracambrian compressional and extensional tectonism. The thickest and areally most extensive basal Silurian organic-rich shales in North Africa occur in Algeria, Tunisia and western Libya, while on the Arabian Peninsula they are most prolific in Saudi Arabia, Oman, Jordan and Iraq. The hot shales were not deposited in Egypt, which was a large palaeohigh at that time. The depositional model presented may help in better understanding the source potential of the basal Silurian shales in less-explored regions of North Africa and Arabia including Morocco, northern Niger and the Kufra Basin in southeast Libya.

Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland

Approximately half of the hydrocarbons discovered in the North Atlantic petroleum provinces are found in sandstones of latest Triassic – Jurassic age with the Middle Jurassic Brent Group, and its correlatives, being the economically most important reservoir unit accounting for approximately 25% of the reserves. Hydrocarbons in these reservoirs are generated mainly from the Upper Jurassic Kimmeridge Clay and its correlatives with additional contributions from Middle Jurassic coal, Lower Jurassic marine shales and Devonian lacustrine shales. Equivalents to these deeply buried rocks crop out in the well-exposed sedimentary basins of East Greenland where more detailed studies are possible and these basins are frequently used for analogue studies (Fig. 1). Investigations in East Greenland have documented four major organic-rich shale units which are potential source rocks for hydrocarbons. They include marine shales of the Upper Permian Ravnefjeld Formation (Fig. 2), the Middle Jurassic Sortehat Formation and the Upper Jurassic Hareelv Formation (Fig. 4) and lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group (Fig. 3; Surlyk et al. 1986b; Dam & Christiansen 1990; Christiansen et al. 1992, 1993; Dam et al. 1995; Krabbe 1996). Potential reservoir units include Upper Permian shallow marine platform and build-up carbonates of the Wegener Halvø Formation, lacustrine sandstones of the Rhaetian–Sinemurian Kap Stewart Group and marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group, the Upper Bajocian – Callovian Pelion Formation and Upper Oxfordian – Kimmeridgian Hareelv Formation (Figs 2–4; Christiansen et al. 1992). The Jurassic sandstones of Jameson Land are well known as excellent analogues for hydrocarbon reservoirs in the northern North Sea and offshore mid-Norway. The best documented examples are the turbidite sands of the Hareelv Formation as an analogue for the Magnus oil field and the many Paleogene oil and gas fields, the shallow marine Pelion Formation as an analogue for the Brent Group in the Viking Graben and correlative Garn Group of the Norwegian Shelf, the Neill Klinter Group as an analogue for the Tilje, Ror, Ile and Not Formations and the Kap Stewart Group for the Åre Formation (Surlyk 1987, 1991; Dam & Surlyk 1995; Dam et al. 1995; Surlyk & Noe-Nygaard 1995; Engkilde & Surlyk in press). The presence of pre-Late Jurassic source rocks in Jameson Land suggests the presence of correlative source rocks offshore mid-Norway where the Upper Jurassic source rocks are not sufficiently deeply buried to generate hydrocarbons. The Upper Permian Ravnefjeld Formation in particular provides a useful source rock analogue both there and in more distant areas such as the Barents Sea. The present paper is a summary of a research project supported by the Danish Ministry of Environment and Energy (Piasecki et al. 1994). The aim of the project is to improve our understanding of the distribution of source and reservoir rocks by the application of sequence stratigraphy to the basin analysis. We have focused on the Upper Permian and uppermost Triassic– Jurassic successions where the presence of source and reservoir rocks are well documented from previous studies. Field work during the summer of 1993 included biostratigraphic, sedimentological and sequence stratigraphic studies of selected time slices and was supplemented by drilling of 11 shallow cores (Piasecki et al. 1994). The results so far arising from this work are collected in Piasecki et al. (1997), and the present summary highlights the petroleum-related implications.

Aneth Oil Field, Giant Carbonate Stratigraphic Trap, Paradox Basin, Utah, U.S.A.

The Aneth oil field (approximately 400 million bbl original primary reserves) occurs within an isolated southeast-northwest-trending Pennsylvanian (Desmoinesian) algal carbonate bank buildup located approximately 25 mi (40 km) basinward of the main carbonate shelf of the Paradox basin in Utah. Desmoinesian deposition was strongly cyclic, with as many as 30 main evaporite-carbonate cycles recognized. The Aneth algal bank is part of the Desert Creek cycle, which is the first cycle above that of the most widespread salt-bearing cycle. The Desert Creek carbonate facies grades basinward to increasingly prevalent evaporite facies, dominated by thick salt beds in the basin center. Within the isolated algal-mound facies, the Desert Creek cycle is characterized by a vertical succession that includes (1) basal black, organic-rich, dolomitic, silty shale, (2) overlying dark chalky, finely crystalline dolomite, which grades upward into (3) the main carbonate mound facies, dominated by accumulations of calcareous, leafy green algae with associated brachiopods, fusulinids, small foraminifera, ostracodes, and rare corals. Mound buildups are overlain by a relatively thin, black, organic-rich shale unit, the basal bed of the succeeding mound-bearing Ismay cycle. This unit thickens markedly on the flanks of the Desert Creek and other mound buildup. Interrelated depositional processes of these variousmore » sedimentary facies have resulted in a close association between source rock, large reservoir, and seal at Aneth, and contributed significantly toward the large size of the Aneth accumulation.« less

Middle Member of Minnelusa Formation (Middle and Upper Pennsylvanian)--Implications for Stratigraphic-Trap Oil Accumulations in Powder River Basin, Wyoming: ABSTRACT

The middle member of the Minnelusa Formation (Middle to Upper Pennsylvanian) thins northward across the Powder River basin from about 150 m thick in the Hartville uplift to less than 50 m near the Wyoming-Montana border. Much of the thinning occurs beneath a regional, pre-Permian unconformity, which is identified in the south half of the basin by a mudstone commonly identified as the red shale marker. Cyclically arranged units up to 10 m thick, composed in ascending order of black organic-rich shale, mud-supported dolomite, anhydrite, and quartzose sandstone, characterize most of the middle Minnelusa. The majority of the sandstone units (informally designated in the subsurface as the Leo sandstones) are less than 3 m thick, tabular shaped, and commonly cemented with anhydrite and dolomite. Locally, however, the sandstones, particularly in the first Leo interval, are lenticular and linear, very porous, and attain thicknesses of more than 15 m. Several of these 10 to 15-m thick, linear first Leo sandstone bodies trend northwest across the southern Powder River basin. They probably represent wadi-type channels that have cut across sabkha and associated peritidal deposits during low st nds of sea level. The source of the Leo sandstones is presently uncertain, but at least the lowermost ones appear to be distal equivalents of the Tensleep Sandstone (Desmoinesian) to the northwest. Where the thicker sandstone units of the first Leo cross anticlinal noses such as at Red Bird, Pine Lodge, and Little Buck Creek, they commonly contain stratigraphically trapped oil. The oil in these fields was probably locally derived from the thin (0.5 to 2 m), widespread, black organic-rich shale units in the middle member. The lenticularity, proposed northwest trend, thickness, porosity, and associated probable source rocks make these sandstone units prime targets for oil and gas exploration in the sparsely tested, deep, southern Powder River basin. End_of_Article - Last_Page 778------------