Shale Environment Research Articles

Mineral composition of the Lower Cambrian black shale in the Upper Yangtze region and its significance in oil and gas exploration

The Lower Cambrian is one of the important exploration strata of marine shale gas reservoirs in the Upper Yangtze region, but its exploration is geologically impacted by multiple factors such as deep burial depth, fewer wells and unsatisfactory exploration results. In this paper, the mineral composition of the Lower Cambrian black shale in the Upper Yangtze region was investigated using the data of X-ray diffraction, rock thin section, scanning electron microscope (SEM) and argon ion polishing-electron microscope, and its significance in oil and gas exploration was also analyzed. The following findings were made. First, shale in this region is mainly composed of clay minerals and quartz, and secondarily of carbonate minerals and feldspar. The average content of quartz in shale is 44.6%, and two types of quartz are developed, i.e. terrigenous quartz and biogenic silica. The average content of clay minerals is 33.32%, with illite (I) content being the highest, illite/smectite (I/S) layer content uneven, the mixed layer ratio lower, generally 5%, and chlorite (C) and kaolinite (K) locally distributed. Second, four types of clay mineral assemblages are identified, including I + I/S + C, transition from I + I/S + C to I + C, I + C, and I, indicating that diagenetic environments of shale are different in different areas. Third, the disordered arrangement of mineral grains is favorable for the survival of intergranular pores, indicating that in the diagenetic alteration process of feldspar into clay minerals, linear pores can be generated. It is concluded that the brittleness index of shale in this region is generally above 40%, indicating a good fragility. The fragility of shale in SE Guizhou is better than that in SW Sichuan Basin.

Draft Genome Sequences of Multiple Frackibacter Strains Isolated from Hydraulically Fractured Shale Environments.

ABSTRACTThe genomes of three novel Frackibacter strains (WG11, WG12, and WG13) were sequenced. These strains were isolated from hypersaline fluid collected from a hydraulically fractured natural gas well. These genomes provide information on the mechanisms necessary for growth in these environments and offer insight into interactions with other community members.

Elemental characteristics of lacustrine oil shale and its controlling factors of palaeo-sedimentary environment on oil yield: a case from Chang 7 oil layer of Triassic Yanchang Formation in southern Ordos Basin

As an important unconventional resource, oil shale has received widespread attention. The oil shale of the Chang 7 oil layer from Triassic Yanchang Formation in Ordos Basin represents the typical lacustrine oil shale in China. Based on analyzing trace elements and oil yield from boreholes samples, characteristics and paleo-sedimentary environments of oil shale and relationship between paleo-sedimentary environment and oil yield were studied. With favorable quality, oil yield of oil shale varies from 1.4% to 9.1%. Geochemical data indicate that the paleo-redox condition of oil shale’s reducing condition from analyses of V/Cr, V/(V + Ni), U/Th, δU, and authigenic uranium. Equivalent Boron, Sp, and Sr/Ba illustrate that paleosalinity of oil shale is dominated by fresh water. The paleoclimate of oil shale is warm and humid by calculating the chemical index of alteration and Sr/Cu. Fe/Ti and (Fe + Mn)/Ti all explain that there were hot water activities during the sedimentary period of oil shale. In terms of Zr/Rb, paleohydrodynamics of oil shale is weak. By means of Co abundance and U/Th, paleo-water-depth of oil shale is from 17.30 to 157.26 m, reflecting sedimentary environment which is mainly in semi deep–deep lake facies. Correlation analyses between oil yield and six paleoenvironmental factors show that the oil yield of oil shale is mainly controlled by paleo-redox conditions, paleoclimate, hot water activities, and depth of water. Paleosalinity and paleohydrodynamics have an inconspicuous influence on oil yield.

Origin of organic matter and paleo-sedimentary environment reconstruction of the Triassic oil shale in Tongchuan City, southern Ordos Basin (China)

Owing to the lack of conventional oil resources, oil shale from the Triassic Yanchang Formation in the southern Ordos Basin has attracted unprecedented attention. The origin of organic matter and the paleo-sedimentary environment of oil shale are discussed. Based on the results of total organic carbon (TOC), total sulfur (TS), rock pyrolysis, organic elements, vitrinite reflectance (Ro), biomarkers, major elements, and trace elements of oil shale from Yishicun Profile, Tongchuan City. The oil shale from the Chang 7 sub-unit has high TOC (0.29–24.68%) and low TS content (0.13–0.61%), exhibiting middle-grade criterion and extra-low sulfur quality. The Ro, together with discrimination diagrams of C29steraneββ/(ββ+αα)-αααC29sterane20S/(20S+20R) and OEP-CPI, suggests that the oil shale has reached maturity. C27−C29 regular steranes distribution, (C19+C20tricyclic terpane)/C23tricyclic terpane, and C23tricyclic terpane/(C23tricyclic terpane+C30hopane) all indicate that the parent materials of the organic matter in the oil shale are algae, phytoplankton, and terrestrial plants. The Pr/Ph, V/Cr, V/(V+Ni), U/Th, δU, and TOC-TS-TFe2O3 ternary diagrams indicate that oil shale mainly deposits in reducing environment with a relatively poor preservation conditions. TS content, gammacerane/αβ-C30hopane, gammacerane/0.5C31αβ(22R+22S), and Equivalent Boron accurately explain that marine transgression did not occur and the paleosalinity of the lake indicates predominantly fresh water. The paleoproductivity of the lake during oil shale sedimentation is very high in terms of U and Mo concentrations and Ba/Al ratio. After quantitative calculation, the lake is classified as an extremely eutrophic lake. The water depth of oil shale sedimentation varies from 26.00 to 108.6m, indicating a semi deep- deep lake.

Sedimentary microfacies and organic geochemical characterization of mudstones in the Keluke Formation in northeastern Qaidam, China

During the Early Carboniferous, the northeastern Qaidam Basin probably formed in an active continental margin setting. Due to marine regression after the late Early Carboniferous, the marginal shelf began to receive more terrestrial clastic sediments, and alternating occurrence of carbonates and siliciclastics characterized this region. Consequently, shales or mudstones with considerable thickness were deposited in the Upper Carboniferous, especially in the Keluke Formation. In order to illuminate a more accurate sedimentary environment of shales and further evaluate the shale gas potential, multidisciplinary traditional methods were conducted including rock core examinations and laboratory analysis. Results reveal that the sedimentary microfacies of shales in the Keluke Formation can be divided into the upper shoreface, the lower shoreface, and the upper to transition offshore. These microfacies developed on a homoclinal carbonate ramp with a gentle slope. The thickest succession of mudstone develops in the lower shoreface, which is a counterpart with the lagoonal setting of a stationary hydraulic system. The quartz content of shale samples ranges from 30% to 66% and clay minerals from 24% to 43% by bulk compositional analysis, which indicates the content of brittle minerals and shales fissility to some extent. The total organic carbon content ranges from 0.5% to 7.6% by weight, with an average value of 2.69% in ZK1‐1 and 1.11% in ZK3‐2, indicating abundant organic matter richness. The kerogen is mainly of type II, which indicates that source for the organic matter is a mixture of higher terrestrial plants and acquatic organisms. The vitrinite reflectance ranges from 1.22% to 1.55%, indicating a moderate to high thermal maturity. Three types of pores are recognized in the shales, including organic pores, intrapartical pores, and interparticle pores. The significance of this work emphasizes two aspects. First, it gives a more detailed classification of sedimentary environment of the mudstone succession; second, it acquires the preliminary subsurface data regarding to the shale gas potential evaluation.

Biomarker signatures of Sinian bitumens in the Moxi–Gaoshiti Bulge of Sichuan Basin, China: Geological significance for paleo-oil reservoirs

The unique Moxi–Gaoshiti Bulge of Sichuan Basin in southwestern China provides insights into the biomarker signatures of bitumens and their geological significance for paleo-oil reservoirs in Precambrian strata. Solid bitumens with various shapes occur widely in the voids, solution pores, cracks, stylolites, and veins of reservoir rocks. Biomarker analysis was conducted on bitumens and the associated source rocks by quantitative detection with gas chromatography–mass spectrometry (GC–MS) to constrain thermal maturity, sedimentary environments, bitumen/paleo-oil sources, and the possible paleo-oil filling directions, which are dominant geological factors that control paleo-oil accumulations. Quantitative analysis of biomarkers showed that the bitumens in the Sinian dolomite of the Moxi–Gaoshiti Bulge belong to the same group. The bitumens are highly matured, and their reflectance values (%Rb) are greater than 1.5 with an average of 2.96. These bitumens originated from thermal cracking of oil (pyrobitmen) via a high-temperature process. The biomarker characteristics revealed that the bitumens and related paleo-oil reservoirs originated from a highly reduced but moderately saline marine shale environment. The marine shales of the Sinian Dengying and lower Cambrian Qiongzhusi formations are their major source rocks. The directions of the primary oil-filling pathways in the Gaoshiti and Moxi sub-bulges are from west to east and from northwest to southeast, respectively. These directions indicate that the Deyang–Anyue sag west of the Moxi–Gaoshiti Bulge is the major hydrocarbon source kitchen.

Dibenzothiophenes in solid bitumens: Use of molecular markers to trace paleo-oil filling orientations in the Lower Cambrian reservoir of the Moxi–Gaoshiti Bulge, Sichuan Basin, southern China

The Moxi–Gaoshiti (MG) Bulge of the Sichuan Basin in southwestern China is unique because of its enormous gas field in old Cambrian and Proterozoic marine strata, where oils in carbonate reservoirs have been nearly completely cracked to solid bitumen and natural gas because of high to post-mature thermal maturity levels. Numerous solid bitumen-bearing dolomites obtained from boreholes in the MG Bulge provide an ideal opportunity to trace the major filling orientations for the Lower Cambrian paleo-oil reservoirs. Biomarker analysis was conducted on solid bitumens through quantitative detection with gas chromatography–mass spectrometry.Results show that all solid bitumen samples in the MG Bulge exhibit similar compositions of molecular markers, thereby implying that they belong to the same oil population and that paleo-oils should be derived from the same source kitchen/bed. Low pristane/phytane and dibenzothiophene (DBT)/phenanthrene ratios, as well as the predominance of DBT among DBT, dibenzofuran, and fluorene, are observed in the solid bitumen samples, which suggest that related paleo-oil reservoirs likely originated from a highly reducing marine shale environment. All isopleth maps of the DBT concentrations, 4-methylDBT/1-methylDBT, 4,6-dimethylDBT/(1,4+1,6)-dimethylDBT (DMDBT), and (2,6+3,6)-DMDBT/(1,4+1,6)-DMDBT ratios consistently indicate that the overall orientation of oil migration in the MG Bulge is primarily from the west-to-east direction, with the strongest filling point located at approximately the Mx12 well. The north-to-west direction is an additional filling orientation. These indicators show that those paleo-oils that had been cracked to pyrobitumens mainly originated from a source kitchen in the western part of the MG Bulge. A hydrocarbon source kitchen in the northern part of the MG Bulge may also have developed but further research on this is needed. The recognition of these solid bitumen molecular signatures, particularly the consistent results using DBT concentrations and alkyl DBT thermal maturity indicators, suggests a potential approach that can be applied to the study of paleo-oil reservoirs.

Depositional environment of oil shale within the second member of Permian Lucaogou Formation in the Santanghu Basin, Northwest China

The non-marine Santanghu Basin in northwest China hosts one of the richest and thickest Permian lacustrine source rock intervals in the world. Conventional oil in Jurassic sandstone reservoirs and tight oil in the tuffaceous Permian Tiaohu Formation were sourced from mudrocks in the underlying second member of Lucaogou Formation, which also have tight oil potential proved by recent commercial discoveries. Based on inorganic and organic geochemistry, organic petrography, and stable isotope geochemistry, the depositional environment and the tight oil potential of the second member of Permian Lucaogou Formation were investigated. The data imply a gradual evolution of the depositional environment from a stratified, saline to a freshwater lake. The succession can be subdivided into a lower, middle, and an upper unit, each characterized by decreasing water salinity. High bioproductivity has been caused by the bloom of algae and photosynthetic cyanobacteria. Water column stratification accelerated the activity of methanothrophs, as indicated by low δ13C values of hopanes. Biomarker composition provides evidence for decreasing contributions of cyanobacteria to the biomass and increasing abundance of Prasinophytae compared to other algae with decreasing salinity. Enhanced terrigenous organic matter input appeared during periods of high freshwater inflow. Low total organic carbon (TOC) contents in the lower unit are most likely caused by rapid sedimentation rate. High bioproductivity and excellent preservation conditions resulted in high TOC contents in the middle unit. Terrigenous organic matter input increased together with fresh water inflow in the upper unit, resulting in high TOC values during periods of possibly low sedimentation rates in a deep water column. The samples of the second member exhibit a good to very good potential to generate conventional oil. High TOC and extractable organic matter yields, together with the thickness of the fine-grained sediments, show that the middle and upper units of the second member of Lucaogou Formation hold significant tight oil potential. Mineralogical composition of this dolomite-rich shale with respect to abundance of brittle minerals (including quartz and carbonates) and rare clay testifies a good tight oil potential.

Depositional environment and micropore characteristics of the Ediacaran Doushantuo Formation black shale in Western Hubei, China

The black shale of the lower Sinian (Neoproterozoic) Doushantuo Formation, located in the Yangtze area (Hubei, China), has a great potential to contain shale gas. The main depositional environments of the region included tidal flats, shelf lagoons, shelf margins, and slopes. While black shale formed from deposits in a shelf lagoon setting, the sediments from the tidal flats were dolomitic. Several factors affect the sediments deposited in these environments, including sediment surface energy (i.e., quiescent or turbulent), salinity, and the presence of either oxic or reducing conditions. The depositional environments of segments B and D of the Doushantuo Formation in the Jiulongwan section were significantly different; specifically, segment D was anoxic to euxinic. As a result, the total organic carbon (TOC) in the segment D shale is higher than that in segment B. This study also used field emission scanning electron microscopy to show that pores in organic matter are the main gas storage space and that the organic matter pores in segment D have diameters less than 100 nm. The increasing of the organic matter content increases organic pore and porosity of the reservoir. TOC is not only the main controlling internal factors of the micropores of the shale in Doushantuo Formation but also provides the important storage space for shale gas. The quiet and hypoxia environment of the black shale in Doushantuo Formation is the main factor controlling the enrichment of organic matter, and the enrichment of organic matter is beneficial to improve the physical property of the shale reservoir. Therefore, black shale formed in the quiet and anoxic depositional environment has better reservoir physical property.

Sedimentary and residual gas geochemical characteristics of the Lower Cambrian organic-rich shales in Southeastern Chongqing, China

To study the sedimentary environment of the Lower Cambrian organic-rich shales and isotopic geochemical characteristics of the residual shale gas, 20 black shale samples from the Niutitang Formation were collected from the Youyang section, located in southeastern Chongqing, China. A combination of geochemical, mineralogical, and trace element studies has been performed on the shale samples from the Lower Cambrian Niutitang Formation, and the results were used to determine the paleoceanic sedimentary environment of this organic-rich shale. The relationships between total organic carbon (TOC) and total sulfur (TS) content, carbon isotope value (δ13Corg), trace element enrichment, and mineral composition suggest that the high-TOC Niutitang shale was deposited in an anoxic environment and that the organic matter was well preserved after burial. Stable carbon isotopes and biomarkers both indicate that the organic matter in the Niutitang black shales was mainly derived from both lower aquatic organisms and algaes and belong to type I kerogen. The oil-prone Niutitang black shales have limited residual hydrocarbons, with low values of S2, IH, and bitumen A. The carbon isotopic distribution of the residual gas indicate that the shale gas stored in the Niutitang black shale was mostly generated from the cracking of residual bitumen and wet gas during a stage of significantly high maturity. One of the more significant observations in this work involves the carbon isotope compositions of the residual gas (C1, C2, and C3) released by rock crushing. A conventional δ13C1–δ13C2 trend was observed, and most δ13C2 values of the residual gases are heavier than those of the organic matter (OM) in the corresponding samples, indicating the splitting of ethane bonds and the release of smaller molecules, leading to 13C enrichment in the residual ethane.

Assessments of oil characterization, source affinities, and hydrocarbon dynamic of East Baghdad oil fields, Central Iraq

Bulk properties, stable carbon isotopes, whole crude Gas-Chromatography and oil mode ratios of sterane and terpanes data of analyzed samples of oil from the Cretaceous Formation reservoirs of East Baghdad oil field are from five producing wells (EB21, EB68, EB92, EB5 and EB31) from reservoirs of Zubair, Khasib, and Tanuma Formations. They are discussed with aids of characters, hopane, tricyclic terpane, isotopic δC13 saturate, aromatics, and pristine-phytane diagrams. The analized oil have indicated light and medium oil in the Zubair reservoirs and heavy oil for the Khasib and Tannuma oil, with about 15% asphalt and porpherine range of 16.7–35.1 Ni and 68–117 ppm, giant reservoirs. The oil source environment and lithology are of marine algal type II and deltaic type II/III that are non biodegraded deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation, aided by pristine-phytane and Tmax equivalent from MDR (Methyldibenzothiophene ratio) diagrams, are showing mature with Tmax 430–435 °C while source age assessment are taken from δC13 (%) and the calculated C28/C29 sterane ratio to be of Middle and Upper Jurassic as well as Lower Cretaceous age that could be correlated mainly with the Chia Gara and Zubair Formations as well as the Middle Jurassic Sargelu Formation source rocks for oil that are accumulated in the reservoirs of Zubair, Khasib and Tannumah Formations.Source rocks are mainly Upper Jurassic-Lower Cretaceous Chia Gara Formation with contribution from the Middle Jurassic Sargelu and Lower Cretaceous Zubair Formations. The richness of the source rocks, mostly due to shale rich in TOC, and the type of kerogen is mixed type II/III and type III. The formations have good petroleum potentiality (PP) and the OM reaches the Early of hydrocarbon generation. Oil, and gas are the most probable product, and the generated hydrocarbons can be expelled at this level of thermal maturity which is confirmed by petromod software basin modeling to suggest migration and accumulation during the Upper Cretaceous time.Hydrocarbon dynamic in East Baghdad Oil Field are performed using seismic section, logs and porosities. Model assessments of the hydrocarbon generation, migration paths and accumulation sites as well as places of enriched oil are used to assess reservoir location and suggestion for drilling sites.

Oil shale paleo-productivity disturbed by sea water in a coal and oil shale bearing succession: A case study from the Paleogene Huangxian basin of Eastern China

Abstract Paleo-productivity has been found to have extensive non-uniformity in the vertical sections of the oil shale layers in the coal and oil shale-bearing successions near the sea which have been disturbed by sea water. It is very important for researchers to analyze the paleo-productivity differences in order to benefit the utilization and exploitation of oil shale. There were a series of coal and oil shale-bearing successions influenced by sea water located in the Huangxian Basin of Eastern China. These include the Oil Shale 1, Coal Bed 1, and Oil Shale 2 deposits. By using sampling analysis, this study determined that Oil Shale 2 (OS2) had been influenced twice by sea water during its deposition process. Six stages were included in the OS2-CB1 depositional process, which were used to build a depositional model. In the first stage, the depositional environment of the oil shale was a fresh water lake, and fresh organisms were the materials of the oil shale. The lake was determined to be a eutrophic lake. In the second stage, the paleo-productivity was down due to a transgression in the tectonic movements, and also due to the fact that the area of the eutrophic lake was shrinking. In the third stage, fresh water was the main supply once again due to the termination of the transgression, and the paleo-productivity was found to be locally increased. A mesotrophic lake lay in the areas near the sea, while a eutrophic lake was located in the middle section of the area. Also, oligotrophic lake deposits were found near the provenances. In the fourth stage, a transgression occurred in the Huangxian Basin due to the basin's subsidence, and the paleo-productivities decreased. A mesotrophic lake type was the main depositional environment in the majority of the areas. In the fifth stage, a fresh water supply was dominant. The paleo-productivities improved, and a eutrophic lake was present. In the sixth stage, a peat swamp developed within the entire basin to the stable tectonic activity. The peat swamp was preserved and coalificated to form a coal bed (CB1). This study's results allowed for the interpretation of the vertical differences in the deposits of oil shale, and the determination the mechanism of the coal and oil shale symbiosis was then possible.

Characterization of water-soluble organic compounds released from black shales and coals

Knowledge of the composition of dissolved organic compounds as well as the main controls on their mobilization from natural organic matter is prerequisite for a comprehensive understanding of the fluid–rock interactions taking place in shale environments and coal seams over both geological and human timescales. In this study, black shales and coals from five different geological settings and covering the maturity range Ro=0.3–2.6% were extracted with deionized water. The dissolved organic carbon (DOC) yields were found to decrease rapidly with increasing diagenesis and remain low throughout catagenesis. Four different fractions of DOC have been qualitatively and quantitatively characterized in the study using size exclusion chromatography (SEC). Acetate is the dominant low molecular weight organic acid (LMWOA) in all extracts of shales and coals of bituminous rank. The concentrations of individual LMWOA also decrease with increasing maturity of the samples except for acetate extracted from the overmature Posidonia shale from the Haddessen well, which was influenced by hydrothermal brines. The positive correlation between the Oxygen Index (OI) and respective LMWOA yield indicates that OI is a significant factor influencing the extraction of organic acids from shales. The yields of both DOC and individual organic acids normalized to TOC are in the same order of magnitude for coals and shales with the same maturity. However, the extracts of coals tend to contain more aromatic compounds and the molecular masses of most constituents included in macromolecular fractions are higher than for shale extracts. These results suggested that different kerogen types show comparable amounts of DOC being extracted, but different DOC composition. Thus, both the origin of organic matter and thermal maturation progress during deposition has significant influence on water extract composition.

E&P Notes (August 2015)

E&P Notes Student-Built Automated Drills Battle Granite for Glory Jack Betz, JPT Staff Writer The Texas A&M University team’s 8-ft maroon-colored drilling machine started lowering its bit to the surface of the test rock. Guided by load, rotation, and vibration sensors, the drawworks inched the topdrive downward in a series of short thrusts before the bit touched the bottom. With the bit in place, a single button push was all it took for the device to begin drilling, after which it required no human guidance. A&M was one of the four finalists in the SPE Drilling Systems Automation Technical Section’s (DSATS) first Drillbotics competition. The two-phase contest required teams of university students to submit plans for automated drills in the fall. Four finalist teams were selected to build machines and test them before judges on their respective campuses in the spring. After an hour-and-a-half of drilling, the power tool buzzing that observers had grown used to hearing began to sound like a jackhammer. “What was that?” one of the competition organizers, Fred Florence, asked the A&M students over the loud rattling. The team members reacted stoically by watching the output of their computer screen more closely, but never looking upset. They had stayed up all night in preparation and contest rules prevented them from making any manual corrections beyond the work already completed over the past year. Major Oil and Gas Discoveries Offshore Mexico Trent Jacobs, JPT Senior Technology Writer In June, Mexico’s national oil company Pemex announced its largest discoveries of oil and gas in 5 years. Located in the shallow-water basin of the Gulf of Mexico offshore Tabasco and Campeche, the four new fields are estimated to hold 350 million bbl of oil. Speaking at the Mexican Petroleum Congress in Guadalajara, Mexico in June, Pemex’s Chief Executive Officer Emilio Lozoya said the fields are expected to produce 200,000 B/D of oil and 170 MMcf/D of natural gas. “The certain prospect of 200,000 extra barrels of production is very good news for Pemex, for the industry, and for our country,” Lozoya was quoted as saying in press reports. He also said first production could be achieved in 16 months. However, Jose Antonio Escalera, director of exploration at Pemex, said in a later interview that the fields would need about 3 years to achieve maximum output. Three of the fields are located in an offshore area known as the Litoral de Tabasco and may add a combined 100,000 B/D of light crude along with 90 MMcf/D of gas. The larger single field in the Sonda de Campeche is expected to add 100,000 B/D of oil and 80 MMcf/D of gas. The last major discoveries on this scale for Pemex were the Tsimin-Xux and Ayatsil fields in 2010. Universities Partner To Create Science Wells Stephen Rassenfoss, JPT Emerging Technology Senior Editor Learning by doing is taking on a new meaning at universities that are constructing “science wells” to study shale exploration and production from below, and above, the surface. West Virginia University has begun drilling two gas wells with a vertical observation well in between them on a site not far from its campus in Morgantown, West Virginia. The heavily instrumented vertical well is at the heart of the work by the Marcellus Shale Energy and Environmental Laboratory, a public/private partnership created to take an unusually detailed and public look at a gas well in the prolific formation. “We thought of it as a tool for teaching, as a research lab, as well as a permanent part of the vision of what we want to do,” said Brian Anderson, director of West Virginia University’s Energy Institute, which coordinates projects including the Marcellus Shale laboratory. The university has partnered with Ohio State University, which is working on a companion effort called the Utica Shale Energy and Environment Laboratory. Both long-term studies plan to look for ways to improve how wells are designed, drilled, and produced, and research how the development of these formations will shape the area’s environment, economy, and public opinion.

Analysis of geological effects on methane adsorption capacity of continental shale: a case study of the Jurassic shale in the Tarim Basin, northwestern China

AbstractThe Jurassic shale is an important source rock for the found gas reservoirs in the Tarim Basin, northwestern China, but has never been researched for shale gas potential. The geological effects on methane adsorption capacity for the gas shale have been investigated in this paper through the geochemical, mineralogical and adsorption analyses on samples from wells and sections. The methane adsorption capacity ranges from 0.58 to 16.57 cm3/g, and the total organic carbon (TOC) content is between 0.5 and 13.5 wt%. The organic maturity measured by Tmax is between 410 °C (immature) and 499 °C (overmature). The methane adsorption capacity of the Jurassic continental shale in the Tarim Basin is affected by many geological factors, including the TOC content, organic matter maturity, mineral composition, surface area and pore size distribution. The TOC content is the most significant factor with a positive effect on the adsorption capacity of the Jurassic shale, and the influence varies piecewise according to the TOC content. The TOC content contributes much more to the methane adsorption capacity of organic‐rich shale samples (TOC content > 0.7 wt%) than to the organic‐lean samples (TOC content < 0.7 wt%). The mineral composition is a secondary factor, and the abundance of clay content has a positive effect on the methane adsorption capacity despite its relatively weaker adsorption ability compared to TOC. The pore size distribution has different effects on surface area and pore volume. Mesopores and micropores provide the major surface area and are mainly derived from TOC and illite, which has a positive influence on the adsorption capacity. Mesopores and macropores offer the major pore volume and are mainly formed by illite, which is the major contributor for pore volume rather than surface area. In addition, the TOC and illite contents of the Jurassic shale in the Tarim Basin are closely related to the origin, maturity and diagenesis evolution of the shale: (1) both TOC and illite content variations are related to the different provenances and depositional environments of shale; (2) the decrease of TOC content with increasing maturity is also partly attributed to hydrocarbon generation; and (3) the increase of illite content with increasing maturity is due to illitization in the diagenesis of shale. Copyright © 2015 John Wiley & Sons, Ltd.

Competition and mimicry: the curious case of chaetae in brachiopods from the middle Cambrian Burgess Shale.

BackgroundOne of the first phyla to acquire biomineralized skeletal elements in the Cambrian, brachiopods represent a vital component in unraveling the early evolution and relationships of the Lophotrochozoa. Critical to improving our understanding of lophotrochozoans is the origin, evolution and function of unbiomineralized morphological features, in particular features such as chaetae that are shared between brachiopods and other lophotrochozoans but are poorly understood and rarely preserved. Micromitra burgessensis and Paterina zenobia from the middle Cambrian Burgess Shale are among the most remarkable examples of fossilized chaetae-bearing brachiopods. The form, functional morphology, evolutionary and ecological significance of their chaetae are studied herein.ResultsLike in Recent forms, the moveable but semi-rigid chaetae fringe both the dorsal and ventral mantle margins, but in terms of length, the chaetae of Burgess Shale taxa can exceed twice the maximum length of the shell from which it projects. This is unique amongst Recent and fossil brachiopod taxa and given their size, prominence and energy investment to the organism certainly had an important functional significance. Micromitra burgessensis individuals are preserved on hard skeletal elements, including conspecific shells, Tubulella and frequently on the spicules of the sponge Pirania muricata, providing direct evidence of an ecological association between two species. Morphological analysis and comparisons with fossil and extant brachiopod chaetae point to a number of potential functions, including sensory, defence, feeding, defouling, mimicry and spatial competition.ConclusionsOur study indicates that it is feasible to link chaetae length to the lack of suitable substrate in the Burgess Shale environment and the increased intraspecific competition associated with this. Our results however, also lend support to the elongated chaetae as an example of Batesian mimicry, of the unpalatable sponge Pirania muricata. We also cannot discount brachiopod chaetae acting as a sensory grille, extending the tactile sensitivity of the mantle into the environment, as an early warning system to approaching predators.Electronic supplementary materialThe online version of this article (doi:10.1186/s12862-015-0314-4) contains supplementary material, which is available to authorized users.

Depositional environment of the Lower Silurian Akkas hot shales in the Western Desert of Iraq: Results from an organic geochemical study

The lower Silurian hot shales in the lower part of Akkas Formation in Akkas field, western Iraq were studied to determine their depositional environments. For this purpose, organic and inorganic proxies were used. These include total organic carbon content (TOC), sulfur, pyrite, and carbonate content measurements, as well as the saturated and aromatic biomarkers. Organic carbon content (TOC), pyrite, and carbonate contents were high and pristane/phytane ratio (Pr/Ph) was low in these hot shales, indicating deposition under anoxic marine conditions. The presence of gammacerane suggests water column stratification; the presence of aryl isoprenoids (originating from aromatic carotenoids of green photosynthetic sulfur bacteria), indicates deposition under euxinic conditions, extending from the photic zone to the sediment–water interface. The conditions became more oxygenated upward, which led to the deposition of organic-poor gray-green shales in the upper part of Akkas Formation, with low pyrite and carbonate contents and high Pr/Ph ratios.

Comparative microbial diversity and redox environments of black shale and stromatolite facies in the Mesoproterozoic Xiamaling Formation

The composition of microbial communities and their relationship to ocean redox structure in the Precambrian are topics of continuing interest in geobiology. Our knowledge of organismic diversity and environmental conditions during this time are mostly based on fragmentary paleontological and geochemical records and might be skewed accordingly. In North China the Xiamaling Formation (∼1.37Ga) is characterized by black shales of relatively low thermal maturity (Tmax is ∼445°C) and has been identified as a potential petroleum source rock. To date, however, the biological sources of the organic matter and the environmental conditions prevalent during the deposition of these sediments remain unclear. In this study we analyzed the hydrocarbon biomarker compositions of the Xiamaling Formation shales and a superjacent stromatolitic carbonate in order to shed light on the microbial diversity in the sedimentary environments they represent. The hydrocarbons extracted from both sediments are dominated by low-molecular-weight n-alkanes with a maximum at C15–18, suggesting that bacteria and/or algae were primary biotic precursors. Our inability to detect steranes in bitumen I, and only traces of rearranged steranes in bitumen II of black shales, indicates that modern eukaryotic algae were either ecologically insignificant or not preserved due to a taphonomic bias. The high relative concentration of hopanes and diahopanes ranging from C27 to C35, as well as monomethylalkanes, suggests that cyanobacteria may have been the dominant primary producers and could have contributed to the biologically available nitrogen pool through N2-fixation. This observation is supported by the low nitrogen isotopic composition of the kerogens. Even though all facies zones appear to have been anoxic but not sulfidic on the basis of biomarker ratios and trace metals, subtle but distinct molecular differences are observed between the stromatolite and the black shales, which can be attributed to both, lithologically-controlled diagenetic rearrangements and differential biotic input. The discrepancy between the presence of a large UCM and high abundances of alkyl lipids on one hand, yet the absence of a stable carbon isotopic offset between lipids and kerogen, on the other, suggests that strong heterotrophic reworking might not be the sole source of the biodegraded fingerprint that is so typical for Proterozoic bitumens, and demands alternative explanations.

Crude oil characterization, molecular affinity, and migration pathways of Halfaya oil field in Mesan Governorate, South Iraq

Nine oil samples of four production wells from Halfaya oil field are selected in this study from the reservoirs of Khasib, Mishrif, and Nahr Umr Formations. They are analyzed chemically for their crude oil characterization as well as isotopes and biomarkers to assess their source rock affinities. Oil biomarkers and isotope values of the analyzed samples from the Nahr Umr, Mishrif, and Khasib Formation reservoirs of Albian, Upper Cenomanian, and Lower Coniacian ages, respectively, from four selected production wells are plotted on sterane triangle, hopane diagram, tricyclic terpane diagram, pristane to phytane ratio with canonian variables, δ13C saturated and aromatic, and pristane/phytane diagrams. They have indicated source environment and lithology of marine algal type II that are nonbiodegraded and deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation are assessed by plots of oil analyzed values on the pristine/phytane diagram. Mature oil are also shown with Tmax equivalent of 435–440 C based on plots of methyldibenzothiophene ratio (MDR) and vitrinite reflectance of Ro = 0.70–0.85 based on methylphenothrene ratio (MPI). Source age assessment are taken from δ13C (%) and the calculated C28/C29 sterane ratio which indicate Middle Jurassic age. Two structural contour maps and two seismic sections are used in this study for assessing source reservoir relations, oil migration paths from the Middle Jurassic Sargelu Formation and accumulation sites in mainly Cretaceous reservoirs. Accordingly, suggestion for risk assessments of drilling sites for hydrocarbon production could be given on the seismic section.

Petroleum system modeling and risk assessments of Ad’daimah oil field: a case study from Mesan Governorate, south Iraq

Oil biomarkers and isotope values of the analyzed samples from the Sa’adi and Yamama Formation reservoirs of Santonian and Valanginian ages, respectively, from well Da-1 as well as Yamama Formation extracts are plotted on sterane triangle, hopane diagram, tricyclic terpane diagram, pristane to phytane ratio with canonian variables, δ13C saturate, aromatics, and pristine-phytane diagrams and have indicated a source environment and lithology of marine algal type II that are nonbiodegraded and deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation is assessed by plots of oil, and the analyzed values of the Yamama source rocks on the pristine-phytane diagram indicate these to be mature with Tmax equivalent of 435 °C based on plots of methyldibenzothiophene ratio (MDR) and vitrinite reflectance of Ro = 0.70–0.85 based on methylphenothrene ratio (MPI). Source age assessment is taken from δ13C (%) and the calculated C28/C29 sterane ratio indicates early Lower Cretaceous age. The Yamama Formation in this study showed excellent hydrocarbon potential with extracted organic matter of up to 16,674 ppm with a total organic carbon (TOC) equivalent of 16.64 wt%. Correlation of the analyzed data from Ad’daimah field with other oil fields in the Mesan Governorate indicates the same characteristics and revealed this to be clustered in one place in all the diagrams, but the source age shows two oil families where the first is sourced from Upper Jurassic-Lower Cretaceous as in the case in the Ad’daimah field while the second is sourced from Middle and Upper Jurassic as in the case in the Halfaya field. Source-oil correlation is confirmed in this study by plots of values from the analysis of Sa’adi and Yamama oil of well Da-1 with the extracts from the Yamama-Sulaiy formations in isotopic δ13C saturate and aromatics, calculated C28/C29 sterane ratio diagram, sterane triangle, and MPI versus Ro. These showed grouping of the oil and extracts of the analyzed data into one place of depositional environment, maturation, and age characteristics that indicate a very good correlation with excellent hydrocarbon generation from the Yamama Formation that measures up to 16,674 ppm of extracted organic matter. PetroMod software basin modeling has confirmed hydrocarbon generation from the Yamama Formation under burial thermal temperature of 114–120 °C with 285–300 mg HC/g TOC for 95 % hydrocarbon transformation from the disseminated organic matters with critical point of hydrocarbon migration and accumulation at 10 million years ago. Palynomorphs have indicated ages of Valanginan-Berriassian for the Yamama Formation and Tithonian-Berriassian for the Sulaiy Formation. Marking places of source rocks and oil reservoir on seismic section across well Da-1 for the Jurassic and Cretaceous strata have shown model assessments of the hydrocarbon generation places of the Yamama Formation, migration pathways and accumulation site, as well as places of enriched oil to assess reservoir sites and suggest for risk assessments of drilling sites for hydrocarbon production from the Yamama and Sa’adi formations. On the other hand, seismic sections in Halfaya and Buzargan fields showed hydrocarbon migration from the Sargelu Formation.