Shale Intervals Research Articles

Paleoenvironmental conditions of organic-rich Upper Permian Dalong Formation shale in the Sichuan Basin, southwestern China

Organic geochemical and trace element analysis of a suite of 33 samples collected from the Shangsi section of the Upper Permian Dalong Formation, located near Guangyuan in the northwestern Sichuan Basin, have been used to better understand the marine depositional environment of its shale lithofacies. A 15 m-thick black shale interval near the middle of the formation is enriched in total organic carbon (TOC = 1.1–14.4%, mean = 6.4%). The n-alkane, terpane and sterane biomarker distributions of the shale suggest that its organic matter is of predominantly marine algal origin. Pr/Ph, Pr/n-C17, Ph/n-C18 and gammacerane/C30 hopane ratios demonstrate that reducing conditions prevailed during its deposition. This interpretation is supported by the redox-sensitive abundance of Mo and the trace element redox ratios Ni/Co, V/Cr, U/Th and V/(V + Ni), all of which indicate deposition in a euxinic/anoxic setting. The Mo-TOC relationship in the Dalong shales plots mid-way between those of sediments in the present-day Saanich Inlet and Cariaco Basin, suggesting a moderately restricted depocentre. However, the δ13Corg values of these shales reveal that their organic matter is isotopically much lighter than that found in modern euxinic sediments, implying extremely anoxic bottom waters and a slow-down of oceanic circulation during the Late Permian.

BURIAL AND THERMAL HISTORY MODELLING OF THE EDIACARAN SUCCESSION IN WESTERN AND SW UKRAINE AND MOLDOVA

The Ediacaran (Upper Neoproterozoic) succession in west and SW Ukraine and Moldova rests on a Cryogenian succession or basement. The succession is exposed at the surface along the southern margin of the Ukrainian Shield and dips to the SW towards the Carpathian Overthrust; where burial depths are sufficient, it is mature for oil and gas generation. The Ediacaran succession is made up of terrigenous siliciclastics ranging from conglomerates and sandstones to siltstones and mudstones, and includes a shale interval (the Kalus Beds) which may have source rock potential. Organic matter in the Kalus shales includes Vendotenides sp. (colonial bacteria) together with amorphous OM. This paper presents a study of the Kalus Beds and is based on data from surface and core samples and thin sections, and the results of Rock‐Eval pyrolysis and reflectance analyses. TOC contents in the Kalus shales are in general <0.5 wt%, although the measured TOC was 0.89 wt% and 0.84 wt%, respectively, in samples from the Sokal‐1 borehole and the Mynkivtsi outcrop location in SW Ukraine. The low present‐day TOC in borehole samples may be due to the thermal transformation of the OM originally present. Reflectivity as measured on vitrinite‐like macerals and bitumen in samples from outcrops ranges from 0.63 to 1.28% VRoeq indicating a relatively low level of thermal maturity. However, the generally low TOC values in the outcrop samples mean that the Kalus Beds in general have little hydrocarbon potential in the study area.The burial and thermal history of the Ediacaran succession in SW Ukraine and the Moldovian Platform was reconstructed, and 1D modelling was carried out at the Brody‐1, Chernivtsi‐1, Dobrotvir‐1, Kolynkiv‐1, Litovyzh‐1, Ludyn‐1, Lyman‐1, Peremyshlyany‐1, Sokal‐1 and Voyutyn‐1 boreholes. The results of modelling indicate that maturities equivalent to the onset of the oil window were reached from the Early Devonian through the Early Carboniferous. Slightly higher modelled maturities occurred in boreholes located near the Teisseyre‐Tornquist Zone. The modelled transformation ratio for kerogen in the Kalus Beds is high and may exceed 90% in the boreholes studied.

Monte Carlo CLEAN Spectral Analysis Method for Detecting the Stratigraphic Cycles Based on High-resolution Electrical Image Log Data

This paper performs a Monte Carlo CLEAN (MC-CLEAN) spectral analysis with high-resolution electrical image log data and interpret the high-resolution formation sequence by investigating the cycles in the sediments. Firstly, in order to perform a spectral analysis with high-resolution electrical image log data, the background conductivity log curve was extracted from the borehole image. Secondly, the MC-CLEAN spectrum analysis method was used to isolate all the peaks of the logging signal. Then the 95% significance level of the CLEAN spectrum was calculated to identify the true period of the formation by Monte Carlo simulation. Finally, the MC-CLEAN spectral analysis method was applied in the two shale intervals from Lower Pannonian interval of Vienna basin to identify the stratigraphic cycles. The analysis results showed that the identified cycles in the sedimentary record good matched the Milankovitch cycles. This paper provided a new approach of identifying stratigraphic cycles and interpreting high-resolution sequence stratigraphy.

Acoustic wave attenuation in the gas hydrate-bearing sediments of Well GC955H, Gulf of Mexico

A better understanding of wave attenuation in hydrate-bearing sediments is necessary for the improved geophysical quantification of marine gas hydrates. Here we compare the attenuation behavior of hydrate-saturated vs water-saturated sediments at site GC955H, in the Gulf of Mexico, which was surveyed during the JIP Leg II expedition. We compute the P-wave attenuation of the gas hydrate bearing sediments using the median frequency shift method on the monopole waveforms. The results show that P-wave attenuation due to low saturation ( 0.4) in the hydrate-filled pores of coarse-grained sediments can be up to as much as three times more than that of the water-saturated case. The correlation analysis shows that the P-wave attenuation increases with the increasing gas hydrate saturation for the highly saturated gas hydrate-bearing sand interval while the correlation of the P-wave attenuation and hydrate saturation is weak for low saturated gas hydrate-bearing shale interval. The results show that P-wave attenuation is more likely to be used as a geophysical proxy for gas hydrate quantification of highly concentrated coarse-grained sediment rather than for that of fine-grained sediment. To examine the P-wave behavior in sand, we use the improved LCAM model, which accounts for physical factors such as grain boundary roughness and squirt flow to explain the observed differences in P-wave attenuation between hydrate and water-saturated coarse-grained sediment. Our results provide further geophysical evidences for P-wave behavior in the gas hydrate-bearing sediments in the field.

Sequence stratigraphy of the lower Pierre Shale of the southern Powder River Basin: A ramp margin sequence that terminates Niobrara Formation carbonate deposition

The Upper Cretaceous section of the southern Powder River Basin of the Rocky Mountain region includes the Niobrara Formation, which is one of the most significant source rocks of the Western Interior Cretaceous Seaway, and it is overlain by the lower Pierre Shale interval. The lower Pierre Shale is divided into eight members, which are the progradational highstand deposits of the Gammon Ferruginous Member; lowstand prograding wedge deposits of the Shannon Sandstone, the Unnamed Member, and the Sussex Sandstone; transgressional Ardmore Pedro Bentonite Beds and Sharon Springs members; and highstand deposits of the Mitten Black Shale and Red Bird Silty members. The Shannon and Sussex Sandstone members are known targets for oil production. Based on integrated research of 1490 well logs with two cores, this study demonstrates that the lower Pierre Shale interval is a Type 1 Ramp Margin Sequence. Although previous studies primarily focused on individual sandstone members or parts of the lower Pierre Shale section in relatively limited areas, this study provides an in-depth sequence stratigraphic analysis of the lower Pierre Shale interval. A depositional model was created, which demonstrates that the Shannon Sandstone, Unnamed, and Sussex Sandstone Members were deposited as an encased lowstand prograding wedge between the progradational Gammon Ferruginous Member and the transgressional Ardmore Pedro Bentonite Beds and Sharon Springs members hundreds of miles basinward from the stratigraphically equal Mesaverde lowstand sandstones of the Bighorn Basin. The shift of facies across long distances is explained with a forced regression that has taken place during the deposition of the uppermost Gammon Ferruginous Member and the following deposition of the Shannon and Sussex sandstone members. Rapid eastward progradation of the clastic sediments of the lower Pierre Shale and the following rapid forced regression effectively terminate the deposition of the Niobrara Formation carbonates in the Western Interior Seaway.

The Silurian stage boundaries in Bulgaria: the challenge of the Aeronian/Telychian (Llandovery) boundary

The upper Aeronian to lower Telychian (Llandovery Series, lower Silurian) strata in the parastratotype for the Saltar Formation (chert-shale succession) are documented in terms of their lithologies and graptolite biostratigraphy. The studied section Asaritsa сrops out in the western sector of the Stara Planina Mountains (Svoge Unit of the Srednogorie Zone). In section Asaritsa, the highest Aeronian graptolitic strata are separated from the lowest Telychian graptolitic strata by a graptolite-barren interval of pale-coloured shale. Based on the graptolites documented below and above this interval, as well as on its correlation to sections studied in detail from the Czech Republic and Spain, the immediate underlay of the pale-coloured shale is referred to the uppermost part of the sedgwickii Zone, the complete pale-coloured shale interval, or its greatest part, to the lower guerichi Zone, and the directly overlying it succession to the upper part of the guerichi Zone. The Aeronian/Telychian boundary is assumed to lie at the base of this pale-coloured shale package, or within its lower part. The study provides documentation of Metaclimacograptus undulatus, Parapetalolithus praecedens, Rastrites carnicus, Rivagraptus bellulus, and illustrations of Stimulograptus for the first time in Bulgaria.

Burial depth interval of the shale brittle\u2013ductile transition zone and its implications in shale gas exploration and production

Brittleness and ductility of shale are closely related to shale gas exploration and production. How to predict brittleness and ductility of shale is one of the key issues in the study of shale gas preservation and hydraulic fracturing treatments. The magnitude of shale brittleness was often determined by brittle mineral content (for example, quartz and feldspars) in shale gas exploration. However, the shale brittleness is also controlled by burial depth. Shale brittle/ductile properties such as brittle, semi-brittle and ductile can mutually transform with burial depth variation. We established a work flow of determining the burial depth interval of brittle–ductile transition zone for a given shale. Two boundaries were employed to divide the burial depth interval of shale brittle/ductile properties. One is the bottom boundary of the brittle zone (BZ), and the other is the top boundary of the ductile zone (DZ). The brittle–ductile transition zone (BDTZ) is between them. The bottom boundary of BZ was determined by the over-consolidation ratio (OCR) threshold value combined with pre-consolidation stress which the shale experienced over geological time. The top boundary of DZ was determined based on the critical confining pressure of brittle–ductile transition. The OCR threshold value and the critical confining pressure were obtained from uniaxial strain and triaxial compression tests. The BZ, DZ and BDTZ of the Lower Silurian Longmaxi shale in some representative shale gas exploration wells in eastern Sichuan and western Hubei areas were determined according to the above work flow. The results show that the BZ varies with the maximum burial depth and the DZ varies with the density of the overlying rocks except for the critical confining pressure. Moreover, the BDTZ determined by the above work flow is probably the best burial depth interval for marine shale gas exploration and production in Southern China. Shale located in the BDTZ is semi-brittle and is not prone to be severely naturally fractured but likely to respond well to hydraulic fracturing. The depth interval of BDTZ determined by our work flow could be a valuable parameter of shale gas estimation in geology and engineering.

Ichnostratigraphy of the Ediacaran-Cambrian boundary: new insights on lower Cambrian biozonations from the Soltanieh Formation of northern Iran

AbstractStrata in the Central Alborz Mountains, northern Iran, are interpreted to show continuous sedimentation from Ediacaran through Cambrian times. The Soltanieh Formation consists of five members: Lower Dolomite, Lower Shale, Middle Dolomite, Upper Shale and Upper Dolomite members. The clastic units (Lower and Upper Shale members) represent sedimentation in distal marine settings, ranging from the shelf to offshore, and contain abundant trace fossils of biostratigraphic utility. Four ichnozones have been recognized. Ichnozone 1, containingHelminthoidichnites tenuis,Helminthopsis tenuis, andCochlichnus anguineus, is early Fortunian based on small shelly fossils, and is interpreted as a distal expression of theTreptichnus pedumzone. Ichnozone 2, comprising the first occurrence ofT.pedum, is middle Fortunian, and is best regarded as the upper half of theTreptichnus pedumZone. Ichnozone 3 is late Fortunian–Cambrian Age 2, characterized by a sudden change in abundance and complexity of trace fossils. Main elements in this ichnozone includeCruziana problematica,Curvolithusisp., Phycodesisp.,Treptichnus pedum,Treptichnus pollardi, andTreptichnusisp. Ichnozone 4 is of Cambrian Age 2–Age 3 and marked by the first appearances ofPsammichnites gigas,Rusophycus avalonensis, andDidymaulichnus miettensis. Integration of trace fossils with small shelly fossils suggests that the Ediacaran–Cambrian boundary should be placed at the base of the Soltanieh Formation or within the Lower Dolomite Member. The delayed appearance ofT.pedumand the low ichnodiversity in the Lower Shale and lower interval of the Upper Shale reflect limited colonization of settings below storm wave base during the early Fortunian.

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.

The radioisotopically constrained Viséan onset of turbidites in the Moravian-Silesian part of the Rhenohercynian foreland basin (Central European Variscides)

The Březina Formation represents the initiation of siliciclastic flysch turbidite sedimentation at the eastern margin of Bohemian Massif or within the Rhenohercynian foreland basin. Its deposition started after drowning of the Devonian carbonate platform during Visean (Mississippian) times, resulting in a significant interval of black siliceous shale and variegated fossiliferous shale deposition in a starved basin. Near the top of the Březina Formation an acidic volcanoclastic layer (tuff) of rhyolitic composition has been dated with high precision U–Pb zircon chemical abrasion isotope dilution method at 337.73 ± 0.16 Ma. This new radiometric age correlates with the previously inferred stratigraphic age of the locality and the current calibration of the Early Carboniferous geologic time scale. Shales of the Březina Formation pass gradually upwards into the siliciclastics of the Rozstani Formation of the Drahany culm facies. Thus our new age offers one of the few available radioisotopic constraints on the time of onset of siliciclastic flysch turbidites in the Rhenohercynian foreland basin of the European Variscides.

Determination of organic degradation rates in 100 My old sediments: Application to Cretaceous black shale intervals from Demerara Rise, ODP Leg 207

Thick organic-rich, Albian to Santonian, black shale sequences were recovered from Ocean Drilling Program Sites 1261 and 1257 on the Demerara Rise, offshore Surinam, at depths of 564 and 174m below seafloor (bsf) respectively. Total organic carbon (TOC) concentration varies between 3.9 and 17.3wt%. Rock-Eval pyrolysis parameters and elemental analysis indicate that the kerogen samples are of Type II, thermally immature and with well preserved organic matter. The hydrogen index (HI) values fluctuate between 608 and 765mghydrocarbon(HC)/gTOC and correlate well with C/N and the Sorg/C atomic ratios, indicating varying early diagenesis conditions between samples. Higher C/N and Sorg/C values for kerogen from Site 1261 suggest more reducing depositional conditions than at Site 1257. Long term organic diagenesis is marked by a linear decrease in the oxygen index (OI) at Site 1261, from 34 to 22mgCO2/gTOC. Ester and carboxyl functional groups are the main target of the degradation as inferred from the decrease in CO and OCC Fourier transform infrared spectroscopy (FTIR) bands as well as in the CHOH and the OCH3/CHxN bands in 13C nuclear magnetic resonance (NMR) spectra. Degradation rate at Site 1261, determined combining quantitative NMR spectra and bulk elemental characterization, is between 1.7 and 12.1µmol/m3/yr per 1% TOC, at the lower end of reported rates in a similar context. Kerogen samples from Site 1257 do not show any decrease in oxygen content with depth, indicating significantly lower degradation rate. We propose that the long term exposure to moderate temperature (30°C) at Site 1261 activated the organic matter, thereby sustaining microbial diagenesis.

The transgressive-regressive cycle of the Romualdo Formation (Araripe Basin): Sedimentary archive of the Early Cretaceous marine ingression in the interior of Northeast Brazil

Geologic events related to the opening of the South Atlantic Ocean deeply influenced the sedimentary record of the Araripe Basin. As consequence, upper stratigraphic units of the basin record a marine ingression in northeastern Brazil during the late Aptian. The timing and stratigraphic architecture of these units are crucial to understand the paleogeography of Gondwana and how the proto-Atlantic Ocean reached interior NE Brazil during the early Cretaceous. This marine ingression is recorded in the Araripe Basin as the Romualdo Formation, characterized by a transgressive-regressive cycle bounded by two regional unconformities. In the eastern part of the basin, the Romualdo depositional sequence comprises coastal alluvial and tide-dominated deposits followed by marine transgressive facies characterized by two fossil-rich intervals: a lower interval of black shales with fossil-rich carbonate concretions (Konservat-Lagerstätten) and an upper level with mollusk-dominated shell beds and shelly limestones. Following the marine ingression, an incomplete regressive succession of marginal-marine facies records the return of continental environments to the basin. The stratigraphic framework based on the correlation of several sections defines a transgressive-regressive cycle with depositional dip towards southeast, decreasing in thickness towards northwest, and with source areas located at the northern side of the basin. The facies-cycle wedge-geometry, together with paleocurrent data, indicates a coastal onlap towards NNW. Therefore, contrary to several paleogeographic scenarios previously proposed, the marine ingression would have reached the western parts of the Araripe Basin from the SSE.

Effects of sand-shale anisotropy on amplitude variation with angle (AVA) modelling: The Sawan gas field (Pakistan) as a key case-study for South Asia's sedimentary basins

Amplitude variation with angle (AVA) is a technique widely used in the characterisation of hydrocarbon reservoirs and assumes the Earth’s crust to be an isotropic medium. Yet, anisotropy is ubiquitous in stratigraphic sequences and has first-order effects on seismic AVA responses when investigating subsurface prospects. This work analyses the effects of anisotropic strata on AVA responses using the Lower Goru Formation, middle Indus basin (Pakistan) as a case study. In the study area, shale intervals are interbedded with reservoir sands of the Sawan gas field. Shales in this field form laminae or are dispersed within reservoir sands, making the Lower Goru Formation an example of a vertically transversely isotropic (VTI) medium. In this work, we calculate the effective (saturated) mechanical properties of the Lower Goru Formation based on rock physics templates; the Backus (1962) average typically designed for layered media, combined with the empirical relations of Brown and Korringa (1975) and Wood (1955). The input data used in our rock physics modelling is based on detailed petrophysical analyses of well data. Using the saturated effective mechanical properties of the Lower Goru Formation, we generate angle-dependent reflection coefficient curves (and seismic AVA responses) based on exact and approximate solutions, for both isotropic and anisotropic reservoir scenarios. Our results suggest that the effects of lithological anisotropy are more pronounced in places with thick shale beds within reservoir sands. Conversely, angle-dependent reflection curves, and seismic AVA responses based on isotropic or anisotropic cases, give similar solutions in the presence of thin shale beds. As a corollary of this work, we present a Bayesian inversion method for the estimation of porosity in VTI media.

Spontaneous Imbibition of Three Leading Shale Formations in the Middle Yangtze Platform, South China

Widely distributed in the Middle Yangtze Platform, Longmaxi, Dalong and Dongyuemiao shales are the most potential target zones for shale gas development in south China. In this study, samples from these main shale gas-producing intervals, with a range of total organic carbon (TOC), mineral compositions, and thermal maturities (from mature to overmature), were selected from three shale gas wells in the Middle Yangtze Platform to investigate their pore structures and spontaneous imbibition characteristics. Mercury injection capillary pressure (MICP) results show the pore throats in these organic shales are mainly within nanometer range, and the pores with pore-throat diameter of 3–50 nm account for 56.7%–73.1% of the total pore volume in mature Dongyuemiao Shale, which is comparative to 51.4%–82.7% for Dalong Shale but smaller than the 68.1%–86.5% range for overmature Longmaxi Shale, which is probably associated with abundance of organic matter-hosted pores in Longmaxi Shale. According to the different imbi...

Calcareous nannofossil biostratigraphy: a tool for understanding the stratigraphic evolution of the Mt. Modino Unit (Northern Apennines, Italy)

The Mt. Modino Unit succession (Northern Apennines) is mainly composed of turbiditic sediments deposited during the collisional and post-collisional stages of the Northern Apennines fold-and-thrust belt. Within this succession we have studied a thick interval of shales with arenitic beds, marls and arenites, of the Fiumalbo Shale, the Marmoreto Marl and the Mt. Modino Sandstone formations. Calcareous nannofossil assemblages of the eight investigated stratigraphic sections contain middle-late Eocene to Oligocene-early Miocene biozones. Zones CNE12 to MNN1 have been identified through quantitative analyses of a set of 200 samples, and the precise ages of the Fiumalbo Shale, the Marmoreto Marl and the Mt. Modino Sandstone were identified as well.The biostratigraphic analyses enable stratigraphic correlations between the investigated sections which were used to propose a stratigraphic architecture of the Mt. Modino Unit succession.Physical and biostratigraphic data available for the Mt. Modino Unit succession suggest a subsiding wedge-top basin fed since the Rupelian by both Apennine and Alpine sources. After the late Oligocene shortening phase, the Mt. Modino Basin occupied the inner part of the foredeep basin, sharing the same turbiditic deposits with the Macigno formation.

Oil retention and porosity evolution in organic-rich shales

Petroleum is retained in shales either in a sorbed state or in a free form within pores and fractures. In shales with oil resource potential, organic matter properties (i.e., richness, quality, and thermal maturity) control oil retention in general. In gas shales, organic pores govern gas occurrence. Although some pores may originate via secondary cracking reactions, it is still largely unclear as to how these pores originate. Here we present case histories mainly for two classic shales, the Mississippian Barnett Shale (Texas) and the Toarcian Posidonia Shale (Lower Saxony, Germany). In both cases, shale intervals enriched in free oil or bitumen are not necessarily associated with the layers richest in organic matter but are instead associated with porous biogenic matrices. However, for the vast bulk of the shale, hydrocarbon retention and porosity evolution are strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation. Secondary organic pores can form only after the maximum kerogen retention (swelling) ability is exceeded at Tmax (the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis) around 445°C (833°F), approximately 0.8% vitrinite reflectance. Shrinkage of kerogen itself leads to the formation of organic nanopores, and associated porosity increase, in the gas window.

Study on the distribution of extractable organic matter in pores of lacustrine shale: An example of Zhangjiatan Shale from the Upper Triassic Yanchang Formation, Ordos Basin, China

Shale oil and gas have been discovered in the lacustrine Zhangjiatan Shale in the southern Ordos Basin, China. To study the distribution of extractable organic matter (EOM) in the Zhangjiatan Shale ([Formula: see text] ranges from 1.25% to 1.28%), geochemical characterization of core samples of different lithologies, scanning electron microscope observations, low-pressure [Formula: see text] and [Formula: see text] adsorption, and helium pycnometry were conducted. The content and saturation of the EOM in the pores were quantitatively characterized. The results show that the distribution of the EOM in the shale interval is heterogeneous. In general, the shale layers have a higher EOM content and saturation than siltstone layers. The total organic content and the original storage capacity control the EOM content in the shale layers. For the siltstone layers, the EOM content is mainly determined by the original storage capacity. On average, 75% of the EOM occurs in the mesopores, followed by 14% in the macropores, and 11% in the micropores. The EOM saturation in the pores decreases with the increase in pore diameter. The distribution of EOM in the shale pores is closely related to the pore type. Micropores and mesopores developed in the kerogens and pyrobitumens and the clay-mineral pores coated with organic matter are most favorable for EOM retention and charging.

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

Evaluation of the shale beds within Alam El Bueib Formation as an unconventional reservoir, Western Desert, Egypt

Within Alam El Bueib Formation (AEB), thin sandstone beds of approximately 15.24 m (~50 ft) total thickness, are considered to be the main conventional hydrocarbon-producing zone in the Western Desert. However, the shale intervals within the AEB can be an unconventional reservoir target. In this study, we focus on evaluating these shale units through geochemical analysis, to determine the total carbon, total sulfur, total organic carbon (TOC), and Rock–Eval pyrolysis. TOC is an essential property needed to determine the productive shale gas play. Total organic carbon combined with other geochemical data is important in evaluating the potential of shale gas reservoirs as it is related to the amount of kerogen, the produced hydrocarbon content. The TOC in the studied samples indicates poor to very good organic continent, while the hydrocarbon potentiality (S1 and S2) indicates poor source potential. The hydrogen index reflected kerogen type III/II. These data indicate that AEB Formation may be considered as a good source for generating hydrocarbons (mainly gas with minor amount of oil). The maturation evaluated by using “Tmax” indicates immature to marginally mature source rock, and production index ‘‘PI” represents oil and gas production in case of maturation.

Shale volume and permeability of the Miocene unconsolidated turbidite sands of Bonga oil field, Niger delta, Nigeria

Bonga oil field is located 120km (75mi) southeast of the Niger Delta, Nigeria. It is a subsea type development located about 3500ft water depth and has produced over 330 mmstb of hydrocarbon till date with over 16 oil producing and water injection wells. The producing formation is the Middle to Late Miocene unconsolidated turbidite sandstones with lateral and vertical homogeneities in reservoir properties. This work, analysis the petrophysical properties of the reservoir units for the purpose of modeling the effect of shale content on permeability in the reservoir. Turbidite sandstones are identified by gamma-ray log signatures as intervals with 26-50 API, while sonic, neutron, resistivity, caliper and other log data are applied to estimate volume of shale ranging between 0.972 v/v for shale intervals and 0.0549 v/v for turbidite sands, water saturation of 0.34 v/v average in most sand intervals, porosity range from 0.010 for shale intervals to 0.49 v/v for clean sands and permeability values for the send interval 11.46 to2634mD, for intervals between 7100 to 9100 ft., Data were analyzed using the Interactive Petrophysical software that splits the whole curve into sand and shale zones and estimates among other petrophysical parameters the shale contents of the prospective zones. While Seismic data revealed reservoir thickness ranging from 25ft to over 140ft well log data within the five wells have identified sands of similar thickness and estimated average permeability of700mD. Within the sand units across the five wells, cross plots of estimated porosity, volume of shale and permeability values reveal strong dependence of permeability on shale volume and a general decrease in permeability in intervals with shale volume. It is concluded that sand units with high shale contents that are from0.500 to0.900v/v will not provide good quality reservoir in the field.