Calcareous Shale Research Articles

Depositional environment of shale in Wufeng and Longmaxi Formations, Sichuan Basin

Formation of organic-rich shale was controlled by depositional processes and environment condition. According to petrology, mineralogy, fossil composition and sedimentary structure, seven lithofacies of shale were identified in the Wufeng Formation to Longmaxi Formation, e.g., siliceous shale, silty shale, argillaceous shale, calcareous shale, shell-bearing argillaceous limestone/calcareous mudstone, siltstone-fine sandstone and bentonite. For shale in the Wufeng and Longmaxi Formations, the depositional mode was not only the suspension deposition under the low-energy hydrodynamic condition, but also the biogenic deposition, the storm deposition and the bottom current deposition indicated by large amount of siliceous biological fossils, biological detritus with size graded structure, silt laminations, lenticular bedding, ripple cross-bedding and other sedimentary structures. Trace element analysis suggested that the siliceous shale in the Wufeng Formation and the lower part of Longmaxi Formation was developed in the oxygen-dysoxic/anoxic depositional environment, which was rich in organic matters; then due to influence of the sea level gradually decline and bottom current, the silty and argillaceous shales were formed, and the oxygen-dysoxic/anoxic depositional environment was destroyed, gradually leading to the worse preservation condition of organic matter.

Dispositional characteristics of Ordovician Wufeng Formation and Silurian Longmaxi Formation in Sichuan Basin and its adjacent areas

According to data of gas wells and typical sections of Wufeng Formation and Longmaxi Formation in Sichuan Basin, shale of various graptolite zones were analyzed to determine depositional environment, lithology and thickness characteristics of the graptolite shale interval of WF2-WF3 in the lower part of Wufeng Formation, the graptolite shale interval of WF4 in Guanyinqiao Member of Wufeng Formation and the graptolite shale interval of LM1-LM4 in the bottom of Longmaxi Formation, and characteristics of shale horizontal distribution were also investigated. During the depositional period of the graptolite shale interval of WF2-WF3, the study area was less affected by the Guangxi movement, the depositional environment was the deep water of open sea, where black shale was mainly deposited; the sedimentation center was developed in northeast Guizhou-northeast Sichuan and south Sichuan, the maximum thickness was from 4 to 6 m in the sedimentation center. During the depositional period of the graptolite shale interval of WF4, the depositional environment in the study area changed greatly due to global sea level fall and enhanced Guangxi movement; the central Sichuan paleouplift, the central Guizhou paleouplift and the Jiangnan-Xuefeng palaeouplift were further expanded, and the area of the sedimentary basin decreased; the depositional environment was mainly carbonate bioclastic shoal of shallow sea, and partially deep sea which only was distributed in the Shizhu-Fuling-Wuxi area in east and northeast Sichuan and the Gongxian-Yongchuan area in south Sichuan; sediments of shallow water were dominated by limestone and argillaceous limestone with abundant Hirnantia, sediments of deep water were dominated by calcareous mudstone and shale with Hirnantia. During the depositional period of the graptolite shale interval of LM1-LM4, due to rise of global sea level and Guangxi movement, the sedimentary area was larger than that in the depositional period of Guanyinqiao Member, and the sedimentary environment mainly was stagnant deepwater; thickness of black shale in the graptolite shale interval of LM1-LM4 was large, and the maximum thickness was over 20 m. Furthermore, control of the central Sichuan paleouplift, the central Guizhou paleouplift and the Jiangnan-Xuefeng paleouplift on black shale was discussed, and control of the Zhiliujing underwater highland/uplift, Huayingshan highland and Dingshan highland as well as western Hubei-Hunan underwater highland/uplift on shale deposition and preservation was also investigated.

Characterization of the Lower Silurian Longmaxi marine shale in Changning area in the south Sichuan Basin, China

On the basis of the core description, thin sections, and geochemistry data, we characterized the Lower Silurian Longmaxi marine shale in the Changning area in the south Sichuan Basin. Ten lithofacies were identified in the Lower Silurian Longmaxi marine shale: (a) massive silty shale (Lithofacies A); (b) laminated siliceous calcareous shale (Lithofacies B); (c) calcareous shale (Lithofacies C); (d) silty dolomitic shale (Lithofacies D); (e) argillaceous siltstone (Lithofacies E); (f) siltstone (Lithofacies F); (g) laminated silty shale (Lithofacies G); (h) silty calcareous shale (Lithofacies H); (i) argillaceous lime shale (marl) (Lithofacies I); and (j) bentonite (Lithofacies J). Obvious heterogeneity occurred in different lithofacies in terms of mineralogy, total organic carbon (TOC) content, porosity, permeability, pore surface area, total pore volume, and total gas content. Among these lithofacies, Lithofacies B has the highest porosity (5.4%), pore surface area (12.79 m2/g), total pore volume (0.015 cc/g), TOC content (4.37%), total gas content (3.4 m3/ton), and relatively high brittle minerals, suggesting great shale gas potential. Lithofacies A, C, and D have a relatively high brittle minerals, porosity, pore surface area, total pore volume, TOC content, and total gas content, which means that these 3 lithofacies show relatively good potential for shale gas. The rest of the lithofacies have low brittle minerals content, porosity, pore surface area, total pore volume, TOC content, and total gas content, representing poor shale gas potential.

Effect of sedimentary environment on shale lithofacies in the lower third member of the Shahejie Formation, Zhanhua Sag, eastern China

Research on shale lithofacies is important for shale oil and gas production. This study focused on the lower third member of the Shahejie Formation ([Formula: see text]) in the Luo-69 well in the Zhanhua Sag, Jiyang Depression, Bohai Bay Basin, eastern China. Several methods, including thin section observations, total organic carbon (TOC) analysis, X-ray diffraction analysis, quantitative evaluations of minerals by scanning electron microscopy, major and trace-element analyses, and field emission-scanning electron microscopy, are used to investigate the effect of sedimentary environment on the type and distribution of shale lithofacies. Our research indicates that 36 types of shale lithofacies can be classified based on the TOC content, mineral composition, and sedimentary structure, of which five types are identified in the study area. The [Formula: see text] shale has a high calcareous mineral content (average of 49.64%), low clay and siliceous minerals contents (averages of 19.54% and 19.02%, respectively), a high TOC content (average of 3.00 wt%), and well-developed horizontal bedding. The sedimentary environment during the deposition of the [Formula: see text] shale in the Zhanhua Sag had a warm and moist climate, limited provenance, saline water, and strong reducibility. The sedimentary environment in the early stage had a drier climate, more limited provenance, higher salinity, and stronger reducibility than that in the later stage. Shale lithofacies can reflect a certain sedimentary environment and depositional process; similarly, a depositional environment controls the type and distribution of shale lithofacies. Due to the characteristics of the [Formula: see text] sedimentary environment, organic-rich massive mixed shale, organic-rich bedded mixed-calcareous shale, organic-rich laminated calcareous shale, and organic-fair laminated calcareous shale are developed in the [Formula: see text] formation from top to bottom.

Lithogeochemical characterization of the Middle–Upper Devonian Road River Group and Canol and Imperial formations on Trail River, east Richardson Mountains, Yukon: age constraints and a depositional model for fine-grained strata in the Lower Paleozoic Richardson trough

Lithogeochemical characterization of the Road River Group and Canol and Imperial formations as exposed at an outcrop on Trail River, eastern Richardson Mountains, documents the evolution of a Laurentian-margin basin during the latest Eifelian through middle Frasnian stages. δ13Corg stable isotope data correlated to conodont-constrained global isotopic curves indicates deposition of the section from ≥387.7 to ≤376.7 Ma. The uppermost Road River Group is latest Eifelian and older in age (≥387.7 Ma) and is primarily calcareous and dolomitic shale and mudstone, representing a slope environment below a carbonate platform that experienced cyclical turbidity current deposition. A 2.3 m, metalliferous and concretionary unit lies transitionally between the Road River Group and Canol Formation and is herein designated as an informal, conformable, lithologic unit called the Road River – Canol transition zone (RCTZ), which records 4.5 Ma of condensed sediment deposition during the Givetian stage (387.7–383.2 Ma). The Canol Formation is confined to the latest Givetian to middle Frasnian stages (383.2–376.7 Ma) and consists of rhythmically bedded, biogenically sourced, siliceous shale and chert that was deposited in an anoxic (and likely euxinic) to oxic basin that evolved from moderately to strongly hydrographically restricted over time. The lowermost Imperial Formation is a siliciclastic mudstone, which documents turbidity current deposition in oxic bottom water conditions in the late Frasnian (≤376.7 Ma). Interpretation of lithofacies, whole-rock geochemistry, mineralogy, and total organic content enable the section to be grouped into eight lithochemozones that record a first-order late-stage sea-level transgression (Road River Group and RCTZ), highstand (lower Canol Formation), and early-stage regression (upper Canol Formation) followed by continued falling stage sea-level conditions with strong detrital influence from a continental collision in the high Arctic (Imperial Formation).

Continental shale pore structure characteristics and their controlling factors: A case study from the lower third member of the Shahejie Formation, Zhanhua Sag, Eastern China

Since shale oil and gas primarily occur in micro-nano pores and fractures, research on pore structure characteristics is important to understand shale oil and gas accumulation mechanisms. Studies on the pore structure of the lower third member of the Shahejie (Es3l) Formation in Zhanhua Sag, Jiyang Depression, Bohai Bay Basin, Eastern China, are quite limited, thereby, restricting further investment on shale oil and gas exploration. We studied continental shale pore structure characteristics and their controlling factors by using a series of laboratory experiments on core samples taken from the Luo-69 Well. The results demonstrate that the Es3l continental shale has a high proportion of calcareous minerals, low siliceous minerals, and low clay minerals. It is characterized by low total organic carbon (TOC) content, low thermal maturity, and Type I and II organic matter. Five different kinds of pore spaces are developed in the shale samples: organic matter-hosted pores, intergranular pores, intercrystalline pores, dissolution pores, and micro-fractures, with the majority of slit-shaped and ink-bottle-shaped pores. Macropores make the greatest contribution to the total pore volume, whereas micropores provide the major surface area. As the organic-rich laminated calcareous shale (ORLCS) presents a larger pore volume, surface area, and mercury withdrawal efficiency, it is a favourable shale lithofacies for shale oil and gas storage and flow. Compared with the Longmaxi marine shale, macropores well-developed in the Es3l shale make great contribution for free hydrocarbon accumulation. Samples with different TOC contents, mineral compositions, thermal maturities, and lamellar layers exhibit distinct differences in pore structure. Mineral composition and thermal maturity primarily affect micropores and mesopores. Macropores are influenced by mineral composition, TOC content, thermal maturity, and lamellar layers.

Lithofacies classification and its effect on pore structure of the Cambrian marine shale in the Upper Yangtze Platform, South China: Evidence from FE-SEM and gas adsorption analysis

Lithofacies classification and storage capacity are of great significance for shale gas. In this study, shale lithofacies classification and its effect on pore structure from the Niutitang shale in the Upper Yangtze Platform were analyzed by experiments of field emission scanning electron microscope (FE-SEM) and gas adsorption analysis. Results show that Niutitang shale can be divided into 12 kinds of shale lithofacies on the basis of TOC content and mineral composition. Pore types and size distribution are significantly distinct of different shale lithofacies since TOC content and mineral compositions do affect shale pore structure differently in their own ways. Specifically, TOC content has the most significant positive effect on shale pore structure, indicating that the higher the TOC content is, the larger the pore volume and surface area are. Negative correlation has been found between calcareous mineral and pore volume and surface area, indicating the decrease of pore volume and surface area with the increase of calcareous mineral content. Compared to argillaceous mineral, siliceous mineral has stronger effect on pore structure. Pore types are also distinctly different in different shale lithofacies which also significantly affect shale gas storage capacity. Organic matter pore is the most abundant pore type in the organic-rich siliceous shale while no OM pore has been found in the organic-poor calcareous shale. Above all, the organic-rich siliceous shale has the largest pore surface area as well as gas storage capacity. While the organic-poor calcareous shale has the smallest gas storage capacity with the poor pore volume and surface area. It would be an effective method to optimize the favorable shale lithofacies in guiding the exploration and development of shale gas.

GEOLOGICAL NOTE

Abstract The term “Sukunka Formation” is proposed for a 113 to 169 metre thick mixed siliciclastic and carbonate unit lying between the Middle Devonian Stone and Dunedin Formations in the Rocky Mountain Front Ranges of northeastern British Columbia. The unit is best developed near the headwaters of the Sukunka River, where it outcrops along a series of closely spaced imbricate thrusts. In the type area, it can be divided into three (informal) members: lower, middle and upper. The lower member overlies the Stone Formation unconformably and consists of inter-bedded orthoquartzite, dolostone and sandy dolostone. It is overlain by the middle member that consists predominantly of brick red weathering siltstones interbedded with minor amounts of dolostone. These ‘red beds’ are readily recognizable in the field and can be used elsewhere in the area to identify thrust imbricates. The upper member consists of a series of thick to massive bedded, well cross-bedded and resistant weathering clean quartzose sandstones which gradationally overlie the middle member. The top of the formation is also disconformable. It is transgressed and overlain by the basal calcareous shales and limes of the Dd-1 member of the Dunedin Formation. However, lag deposits from the Sukunka Formation occur within the basal calcareous shales and limes of the Dd-1 member. This condition is thought to reflect progressive transgression of higher stratigraphic levels of the Sukunka Formation to the east by the rising waters that led to accumulation of the Dunedin Formation. Diagnostic fossils have not been recognized in the Sukunka Formation. Presently, it is dated as early Middle Devonian based solely on stratigraphic position. In the subsurface, in the same stratigraphic position between the Stone and Dunedin formations, unnamed argillaceous, sandy and silty carbonates have also been identified. These, further to the east, may be equivalent to the unnamed detrital unit of the Chinchaga Formation.

The application of geostatistical inversion in shale lithofacies prediction: a case study of the Lower Silurian Longmaxi marine shale in Fuling area in the southeast Sichuan Basin, China

Based on cores, well logs and seismic data, we established the isochronous sequence stratigraphic framework of the Lower Silurian Longmaxi Formation and predicted the shale lithofacies distribution within the sequence stratigraphic framework using geostatistical inversion. The results of our study show that the Lower Member of the Longmaxi Formation is a third order sequence that includes a transgressive systems tract (TST), an early highstand systems tract (EHST) and a late highstand systems tract (LHST). Four lithofacies units have been recognized, specifically siliceous shale, argillaceous shale, calcareous shale and mixed shale. The results of geostatistical inversion reveal that the TST is characterized by flaky siliceous shale and some sparsely distributed calcareous shale. The EHST is dominated by mixed shale with minor amounts of siliceous shale, which occurs in only a small area. Moreover, in the LHST, argillaceous shale occupies almost the entire study region. Comparing to traditional geological research with geophysical research, the vertical resolution of the predictive results of geostatistical inversion could reach 1–2 m. Geostatistical inversion effectively solves the problem of precisely identifying the lithofacies in the Fuling shale gas field and predicting their spatial distribution. This successful study showcases the potential of this method for carrying out marine shale lithofacies prediction in China and other locations with similar geological backgrounds.

Foraminíferos planctônicos e bentônicos cretáceos da Ilha de Quiepe, Formação Algodões, Bacia de Camamu, Bahia, Brasil

A sampling program from Camamu Bay and its neighborhood were undertaken to microfossils appraisal of the Algodoes Formation outcrops, Camamu Basin. Among the basins of the Brazilian eastern margin, the Camamu Basin is the least known. This study aimed to identify planktonic and benthonic foraminifera of the Algodoes Formation, Camamu Basin, and to make biostratigraphic, paleoecological and paleobiogeographic inferences based on the microfauna. The sampling points were located at the Boipeba Island (Boipeba and Tassimirim beaches), and at the Camamu Bay (Barra Grande and Taipus de Fora beaches; Quiepe and Cangaiba islands). In total, 50 rock samples were collected, constituted in great part of calcarenites, besides dolomites, calcilutites and calcareous shale. All the material was subjected to a three laboratory techniques, applied to recover or observe carbonate microfossils: thin section, acetolysis and hydrogen peroxide methods. Only five samples from Quiepe Island showed results. Planktonic foraminifera, belonging to the genus Whiteinella (W. aff. aprica, W. archaeocretacea, W. baltica and Whiteinella sp. 1) were identified, besides scarce specimens assigned to Hedbergella (Hedbergella ? sp.1). The paleoecological studies, based on the benthonic foraminifera, revealed predominance of calcareous specimens (Bolivinidae ?), followed by agglutinated taxa (Spiroplectamminidae ? and Textulariidae ?). The occurrence of W. aff. aprica, W. archaeocretacea and W. baltica in the planktonic assemblage suggests a upper Cenomanian to upper Turonian age for the studied section of the Algodoes Formation. However, the correlation with ammonites data (Mammites, Kamerunoceras, Romaniceras and Neoptychites) allows to a better biostratigraphic resolution, indicating strata of early-middle Turonian age. The benthonic foraminifera observed (Bolivinidae ?, Spiroplectamminidae ? and Textulariidae?) indicated the predominance of infaunal organisms that lived on substrates constituted by calcareous mud preferably, and probably occupied the middle-deep neritic paleobathymetric range. The finding of Whiteinella (W. aff. aprica, W. archaeocretacea, W. baltica, Whiteinella sp. 1), besides the ostracod specimens of the Sapucariella ex gr. sapucariensis are important biogeographical records in the upper Cretaceous of South America and Africa.

Lithofacies and sedimentary sequence of the lower Cambrian Niutitang shale in the upper Yangtze platform, South China

The lower Cambrian Niutitang shale in the Upper Yangtze Platform is a hot target for shale gas exploration in China. In this paper, the lithofacies and sedimentary evolution characteristics about this shale formation are studied on the basis of outcrop investigation and experimental measurements. The variations on geochemistry, mineralogy, lithofacies and stratigraphic architecture of this shale are analyzed. This shale is rich in organic matter, with an average TOC content of 5.5%. Quartz and clay mineral dominate the mineral composition, with an average content of 57.3% and 29.8%, respectively. The TOC content correlates positively to quartz content, but negatively to clay mineral content. Trace element ratios of V/Cr, V/(V + Ni) and Ni/Co indicate anoxic to dysoxic conditions prevailed during the Niutitang shale deposition period in Early Cambrian, and moderate to weak degree of restriction are inferred by the covariation of Mo and TOC content. Five lithofacies are identified based on TOC content, mineral composition, texture and fabric: organic-rich siliceous shale, silty siliceous shale, calcareous siliceous shale, argillaceous shale, and silty mixed shale. Four lithofacies associations are interpreted to represent four different depositional facies from shelf margin to abyssal environments. The Niutitang Formation generally shows a shallowing-upward prograding depositional sequence and can be divided into two large shale cycles. From bottom to top, the organic matter content and anoxic degree decreases largely with the sea level fall. The average content of quartz deceases, but the average content of clay mineral increases. Stratigraphic correlation for this shale reveals an obviously decreasing trend of quartz content, but an increasing trend of organic matter and clay mineral contents from slope to basinal facies.

The drowning of a siliciclastic shelf: insights into oceanographic reconstructions of the northern Arabian Platform during the Early Cretaceous

AbstractBarremian‐Aptian sedimentary successions along the northern Arabian margin have been described as a transition from a siliciclastic to a carbonate‐dominated marine environment, deposited upon a low‐relief shelf or platform formed as a consequence of continuous regional subsidence. A long (360 m) core from northern Israel offers a unique look at this transition, providing valuable insights for the palaeoceanography, geometry and ventilation conditions that lead to Oceanic Anoxic Event 1 (OAE1) in this region. Results from high‐resolution elemental, mineralogical, sedimentological and petrophysical analyses carried out revealed the emplacement of abundant mass‐transport deposits (MTDs) during the Late Barremian and the Aptian. The transplanted units are characterized by fine grained calcareous shales with elevated organic matter, sulphur and iron contents. The scarcity or absence of bioturbation in the disturbed sequences provides a hint to the sediment/water interface conditions. However, a decrease in sulphur and iron occurring at the contact between the shales and the MTDs is explained as increased oxic conditions at the sediment‐water interface as a result of turbulence and mixing associated with the descending sediment masses. Such recurrent events ventilation of the low‐energy basinal environment during the Late Barremian and Aptian, predate the wide‐scale establishment of OAE1 in the northern Arabian margin. Moreover, the identification of coarse‐grained MTDs within deep‐water calcareous sediments indicates a much steeper gradient of the northern Arabian margin, challenging previous studies.

Hypogenic karst beneath the Athabasca Oil Sands: Implications for oil sands mining operations

The Athabasca Oil Sands, located in northeast Alberta, largely comprise a stacked succession of Early Cretaceous fluvial and marine sediments that were deposited directly above Middle and Late Devonian limestones, dolostones, calcareous shales and evaporites. Dissolution of halite and anhydrite from the Prairie Evaporite Formation by hypogenic karstification has resulted in the diachronous subsidence of overlying stratigraphic units and severe brecciation of important aquitards. These aquitards are required to protect oil sands mining operations from in-pit influxes of saline water sourced from Devonian aquifers. Sequence stratigraphic, palynologic and groundwater isotopic evidence suggests that karstification began prior to the Early Cretaceous, was active during deposition of the McMurray Formation and is still ongoing today in the Athabasca Oil Sands mining area. Groundwater flow associated with hypogenic karstification has important implications for the development of the Athabasca Oil Sands. For in-situ projects, Devonian aquifers are considered both as a resource for the moderately saline water required for steam generation and as a disposal zone for waste water. In open-pit oil sands mines, some of the most effective aquitards are removed by mining operations, thereby increasing the possibility that saline water from the Devonian aquifers could enter the mine pits. This poses safety, environmental and economic risks to mining operations that require a thorough understanding of the geologic, hydraulic and geomechanical controls related to hypogenic karstification. This paper, presents our current understanding of the hypogenic karst system in the vicinity of the Kearl mine.

Metamorphosis of Marine Organic Matter in the Jurassic Deposits from Sharab Area, Taiz Governorate of Southwestern Yemen: Thermal Effect of Tertiary Volcanic Rocks

ABSTRACT The Tertiary volcanic rocks are widely exposed in the Sharab area of Taiz Governorate, southwestern Yemen. The Jurassic calcareous shale and black limestone deposits collected closely to the Tertiary volcanic rocks were investigated to provide information regarding the thermal effects of Tertiary volcanic rocks on organic materials. The bulk geochemical results indicate that the analysed Jurassic deposits are organically lean with present-day TOC values less than 0.95% and very low HI values (< 50 mg HC/g TOC), with a predominantly Type IV kerogen (inert carbon). This is attributed to thermal effect on the original organic matter as indicated by high thermal maturity data, consistent with postmature to metagenesis stage. The present study also suggests that the high thermal maturity of the Jurassic marine deposits is due to the presence of the alkali basalts which have invaded the Jurassic rocks during late Oligocene to early Miocene (∼10 Ma). Thus, the heat flow caused by Tertiary basaltic rocks further increased the temperature level and led to metamorphosis of organic matter and converted it to graphitic materials (inert carbon).

Upper Jurassic–lowermost Cretaceous marine shale source rocks (Farsund Formation), North Sea: Kerogen composition and quality and the adverse effect of oil-based mud contamination on organic geochemical analyses

The Jude-1 well is located in the central part of the Danish Central Graben, North Sea, and was drilled into immature black shales of the Upper Jurassic–lowermost Farsund Formation, a world-class marine source rock. The well was drilled with oil-based drilling mud (OBM). The lithofacies consists of argillaceous shale, calcareous shale and dolomite stringers as confirmed by cuttings and core. A core was taken in the upper part of the formation at the beginning of a ‘hot’ argillaceous shale interval characterized by elevated TOC and HI values. Cuttings and core samples were investigated to unravel kerogen composition, source rock quality and the contamination effect of OBM on organic geochemical analyses. The organic facies of the source rocks corresponds to Type II kerogen or Organofacies B (sensu Pepper and Corvi, 1995). Considerable fluctuations in HI values through the Farsund Formation reflect pronounced variations in source rock quality, although a faint lamination of the shales and overall high TOC contents testify to prevailing oxygen-deficient depositional conditions preventing significant bioturbation and reworking of the sediment and organic matter. Petrography of core samples reveals a relatively homogenous sapropelic kerogen composition dominated by a groundmass of yellowish fluorescing amorphous organic matter and liptodetrinite intimately associated with the mineral matrix. Telalginite is less abundant, but Tasmanites- and in particular Leiosphaerida-type telalginites were observed. Minor but varying amounts of detrital terrigenous macerals suggest a considerable distance to land areas and thus limited supply of land plant-derived organic matter. The argillaceous shale lithofacies generally is more oil-prone and organic-rich than the more gas-prone calcareous shale facies. The uppermost section includes the ‘hot’ argillaceous shales, which together with two deeper argillaceous shale intervals are highly organic-rich and oil-prone. Average TOC of the ‘hot’ argillaceous shales is ~7wt% and HI reaches >500mgHC/gTOC. The total Ultimate Expulsion Potential (UEP) of the over 853m (2799ft) thick Farsund Formation is ~142mmboe/km2. Results from non-contaminated samples are thus consistent with the Farsund Formation being a world-class highly oil-prone marine source rock. The predicted oil composition corresponds to ‘paraffinic low wax oils’. The adverse effect of OBM contamination on geochemical analyses is demonstrated by Rock-Eval data and measured bulk kinetics of contaminated core samples. The measured kinetics has a considerable proportion of low activation energies related to OBM contamination which is also supported by high Production Indices. Further, gas chromatograms of the saturated fraction of extracts from contaminated cores clearly show evidence of OBM in the nC11–nC14 range. Rock-Eval S2 peaks have a ‘shoulder’ showing that the low Ea-peaks result from carry over from the S1 peak, caused by the OBM contamination. As a consequence Hydrogen Index values are increased.

Recharge mechanism and processes controlling groundwater chemistry in a Precambrian sedimentary terrain: a case study from Central India

Unplanned and unsustainable extraction has created stress on groundwater resources in many parts of India. The stress symptoms are more pronounced in hard rock areas, where the aquifer potentials are comparatively low. Present research targeted an area of 3000 km2 in the interstream region between the Kharun and Seonath rivers, which is one such region in Central India. In spite of being a water-stressed area, so far, little is understood about processes of recharge, amount of recharge and processes controlling chemical quality, which are key inputs for groundwater management in the area. This study presents an appraisal of recharge mechanism, recharge rate and prevailing water–rock interactions in the study area. Stable isotope composition of groundwater when compared to that of rainfall indicates monsoon rainfall as the primary source of groundwater recharge. Winter rains, which are characteristically enriched in heavier isotopes, do not contribute notably to groundwater recharge. Recharge is rapid with minor or no evaporative enrichment before recharge. Further, analysis of stable isotopes show that ‘macropore recharge’ is dominant in limestone or calcareous shale, covering more than 70% of the study area. Also apparent is the vertical connectivity amongst the aquifers. However, active intermixing of surface water and groundwater is not a predominant process. Annual groundwater recharge from rainfall, as derived from chloride mass balance, is 105.26 million cubic metre. Groundwater is predominantly of bicarbonate type, irrespective of its hydrostratigraphic (lithology) setting. Dissolution of carbonates and gypsum (occurring as veins), weathering of feldspar and ion exchange of clay minerals are amongst the most likely processes controlling the regional groundwater chemistry.

Geochemical characterization of the Jurassic Amran deposits from Sharab area (SW Yemen): Origin of organic matter, paleoenvironmental and paleoclimate conditions during deposition

Calcareous shales and black limestones of the Jurassic Amran Group, located in the Sharab area (SW Yemen), were analysed based on organic and inorganic geochemical methods. The results of this study were used to reconstruct the paleoenvironmental and paleoclimatic conditions during Jurassic time and their relevance to organic matter enrichment during deposition of the Amran calcareous shale and black limestone deposits. The analysed Amran samples have present-day TOC and Stotal content values in the range of 0.25–0.91 wt % and 0.59–4.96 wt %, respectively. The relationship between Stotal and TOC contents indicates that the Jurassic Amran deposits were deposited in a marine environment as supported by biomarker environmental indicators. Biomarker distributions also reflect that the analysed Amran deposits received high contributions of marine organic matter (e.g., algal and microbial) with minor amount of land plant source inputs. Low oxygen (reducing) conditions during deposition of the Jurassic Amran deposits are indicated from low Pr/Ph values and relatively high elemental ratios of V/Ni and V/(V + Ni). Enrichment in the pyrite grains and very high DOPT and high Fe/Al ratios further suggest reducing bottom waters. This paleo-redox (i.e., reducing) conditions contributed to preservation of organic matter during deposition of the Jurassic Amran deposits. Semi-arid to warm climatic conditions are also evidenced during deposition of the Amran sediments and consequently increased biological productivity within the photic zone of the water column during deposition. Therefore, the increased bio-productivity in combination with good preservation of organic matter identified as the major mechanisms that gave rise to organic matter enrichment. This contradicts with the low organic matter content of the present-day TOC values of less than 1%. The biomarker maturity data indicate that the analysed Amran samples are of high thermal maturity; therefore, the low present-day TOC is attributed to the thermal effect on the original organic matter. This high thermal maturity level is due to the presence of volcanic rocks, which have invaded the Jurassic rocks during Late Oligocene to Early Miocene.

Mineralogical and chemical distribution of the Es3L oil shale in the Jiyang Depression, Bohai Bay Basin (E China): Implications for paleoenvironmental reconstruction and organic matter accumulation

The Es3L (lower sub-member of the third member of the Eocene Shahejie Formation) shale in the Jiyang Depression is a set of relatively thick and widely deposited lacustrine sediments with elevated organic carbon, and is considered to be one of the most important source rocks in East China. We can determine the mineralogy, organic and inorganic geochemistry of the Es3L shale and calculate paleoclimate indexes by using multiple geochemical proxies based on organic chemistry (total organic carbon [TOC] and Rock-Eval pyrolysis), major and trace elements, X-Ray diffraction, and carbon and oxygen isotope data from key wells alongside ECS (Elemental Capture Spectroscopy) well log data. These indicators can be used to analyze the evolution of the paleoenvironment and provide a mechanism of organic matter (OM) accumulation. The Es3L oil shale has high TOC abundance (most samples >3.0%) and is dominated by Type I kerogens. Additionally, the organic-rich shale is rich in CaO and enrichment in some trace metals is present, such as Sr, Ba and U. The positive δ13C and negative δ18O values, high Sr/Ba, B/Ga and Ca/Ca + Fe ratios and low C/S ratios indicate that the Es3L shales were mainly deposited in a semi-closed freshwater-brackish water lacustrine environment. The consistently low Ti/Al and Si/Al ratios reflect a restricted but rather homogeneous nature for the detrital supply. Many redox indicators, including the Th/U, V/(V + Ni), and δU ratios, pyrite morphology and TOC-TS-Fe diagrams suggest deposition under dysoxic to suboxic conditions. Subsequently, the brackish saline bottom water evolved into an anoxic water body under a relatively arid environment, during which organic-lean marls were deposited in the early stage. Later, an enhanced warm-humid climate provided an abundant mineral nutrient supply and promoted the accumulation of algal material. OM input from algal blooms reached a maximum during the deposition of the organic-rich calcareous shale with seasonal laminations. High P/Ti ratios and a strongly positive relationship between the P and TOC contents indicate that OM accumulation in the oil shale was mainly controlled by the high primary productivity of surface waters with help from a less stratified water column. Factors such as the physical protection of clay minerals and the dilution of detrital influx show less influence on OM enrichment.

Geochemical Characteristics and Modeling of Conventional Petroleum System of Majnoon Oil Field, South Iraq

Organic geochemical analysis and model set–up to simulate the genetic relationships among 18 crude oil samples recovered from different formations and various oil fields within Amara city South Iraq, with depths approximately begin from 2167 to 4430 m, ages of marine carbonates sourced from Middle Jurassic age (Sargelu Formation) according to geochemical similarities appointed previously for this period. The levels of maturation are relatively varied for each sample from low to moderate, MJ-1, MJ-18 (Hartha Formation), MJ-3, MJ-10 (Mishrif Formation), MJ-9 (Nahr Umr Formation), MJ-15 (ZubairFormation), MJ-2, MJ-19(Nahr Umr Formation MJ- 10,MJ-11(Zubair Formation) MJ-3 (Nahr Umr Formation), Mj-3 (Sulaiy Formation), MJ-12 (two samples) Sulaiy Formation MJ-11, MJ-2 (Nahr Umr Formation), MJ-2 (Zubair Formation), MJ-11 (Sulaiy Formation )of Amara city Oil fields.These samples suggest the ages and paleoenvironments of their source rocks. The samples were collected from Upper Jurassic to Cretaceous reservoirs of 18 developed oil fields where about 15 billion barrels of recoverable oil have been reserved.The oil density varies in rather wide range, between 12.2 and 39.2 API. Twelve oil samples are ˂25 API referring to heavy oil and only oil samples attained defiantly from 25 to 35API are medium oil. Canonial Variables (CV) range attain to (- 1.89 to – 3.99) of waxy oil. According to the Tissot and Welte’s classification (1984), most of the oils can be classified as ‘‘high sulfur’’ oils/indicate that these samples are of marine origin.Stable Carbon Isotope Composition C15+ Saturate and Aromatic is relatively approximate values giving good supporting evidences for the same family which is Middle Jurassic Age (sourced from Sargelu Formation), generated within the sedimentation of the bituminous calcareous shale and Limestone in Mesopotamian basin. This basin consider as one of the most formative, potential and promising basin in the Middle East according to the typical petroleum system elements. This family was generated by marine carbonate - intrashelf sub basin source rocks, occurring in Jurassic – Cretaceous – Neogene reservoir rocks of Mesopotamian basin which are geochemically similar to the extracts from Middle –Upper Jurassic age (Sargelu Formations), yielding the majority of petroleum oil and gas fields in north and south Iraq. Petroleum system modeling in one dimension (1-D Petro Mod) was performed using Petro Mod basin modeling software which developed by Integrated Exploration System (IES) to demonstrate burial thermal history hydrocarbon generation and expulsion for Majnoon oil field so that 1-D Petro Mod was applied to Nine wells (Mj-2, Mj-3, Mj-4, Mj-8, Mj-9, Mj-11, Mj-12, Mj-15, and Mj-19) following the procedure of Pitman et al 2004.

Refining 2 km of Ordovician chronostratigraphy beneath Anticosti Island utilizing integrated chemostratigraphy

New high-resolution chemostratigraphy, in combination with updated biostratigraphy, refines the chronostratigraphic resolution of the nearly 2 km thick Ordovician section below Anticosti Island. A total of 1414 horizons, spaced at 1.0–1.5 m intervals, were sampled from the New Associated Consolidated Paper (NACP) drill core and analyzed for major and trace elemental composition by portable X-ray fluorescence analyzer (pXRF). Select micrite and calcareous shale powders were then analyzed for δ13Ccarb (number of samples, N = 364) and 87Sr/86Sr (N = 25). Our results indicate a Floian to early Darriwilian (F3–Dw1) age for the Romaine Formation, a middle Darriwilian to Sandbian (Dw2–Sa1) age for the Mingan Formation, a lower to mid-Katian (Ka1–Ka2) age for the Macasty Formation, an upper Katian (Ka3) age for the lower Vauréal Formation, an uppermost Katian (Ka4) age for the upper Vauréal, and a Hirnantian (H1) age for the Ellis Bay Formation. This integrated chemostratigraphic and biostratigraphic synthesis establishes the position of numerous unconformities, the duration of the intervening depositional sequences, and rates of sedimentation.