Influence of refractory organic matter on source rock hydrocarbon potential: A case study from the Second White Specks and Belle Fourche formations,Alberta, Canada

Dilution by inert, refractory organic carbon can have a significant impact on the hydrocarbon potential of source rocks. In this study, a correction of total organic carbon, based on petrographic observations, is proposed to give a better indication of hydrocarbon generation potential. This correction shows that although the Second White Specks Formation is an excellent hydrocarbon source rock, hydrogen index and total organic carbon are influenced by dilution from refractory organic carbon of various sources. The results show that a higher degree of dilution occurs within the Belle Fourche Formation than the Second White Specks Formation. This dilution can have a significant impact on the hydrocarbon potential of the rock.Volumetric calculation of the inert carbon fraction using organic petrographic methods provides a semi quantitative method to correct total organic carbon values for the refractory organic carbon dilution effect. Incorporation of the dilution corrected organic carbon value in hydrogen index calculations allows a greater understanding of source rock hydrocarbon potential. This method provides better differentiation of the small scale variation between micro-facies and formation, as observed in the Second White Specks and Belle Fourche formations, than traditional bulk geochemical methodologies and previously proposed correction methodologies. Degree of dilution, either through transport of recycled allochthonous or autochthonous reworking of organic matter in-situ is highly variable and represents a significant challenge in the characterization of heterogeneous source rocks.This study investigates the organic petrology and geochemistry of a sediment core from the thermally immature area of the Upper Cretaceous Second White Specks Formation and Belle Fourche Formation. Reflectance and relative abundance of three maceral groups (bituminite, alginite, and refractory organic carbon macerals) showed significant organic matter compositional differences between micro-facies in the Second White Specks Formation. A change is also observed in organic matter composition from the upper part of the Belle Fourche Formation to the Second White Specks Formation. These compositional changes represent shifts in sediment source, sea floor oxygen levels, and depositional energy levels. These changes can be episodic, as observed between micro-facies, or longer time scale trends, as observed between the studied formations.     

Thermal maturity,source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin,Eastern India

This study investigates the source rock characteristics of Permian shales from the Jharia sub-basin of Damodar Valley in Eastern India. Borehole shales from the Raniganj, Barren Measure and Barakar Formations were subjected to bulk and quantitative pyrolysis, carbon isotope measurements, mineral identification and organic petrography. The results obtained were used to predict the abundance, source and maturity of kerogen, along with kinetic parameters for its thermal breakdown into simpler hydrocarbons.The shales are characterized by a high TOC (>3.4%), mature to post-mature, heterogeneous Type II–III kerogen. Raniganj and Barren Measure shales are in mature, late oil generation stage (Rr%_Raniganj = 0.99–1.22; Rr%_{Barren Measure} = 1.1–1.41). Vitrinite is the dominant maceral in these shales. Barakar shows a post-mature kerogen in gas generation stage (Rr%_Barakar = 1.11–2.0) and consist mainly of inertinite and vitrinite. The δ¹³C_org value of kerogen concentrate from Barren Measure shale indicates a lacustrine/marine origin (−24.6–−30.84‰ vs. VPDB) and that of Raniganj and Barakar (−22.72–−25.03‰ vs. VPDB) show the organic provenance to be continental. The δ¹³C ratio of thermo-labile hydrocarbons (C₁–C₃) in Barren Measure suggests a thermogenic source.Discrete bulk kinetic parameters indicate that Raniganj has lower activation energies (ΔE = 42–62 kcal/mol) compared to Barren Measure and Barakar (ΔE = 44–68 kcal/mol). Temperature for onset (10%), middle (50%) and end (90%) of kerogen transformation is least for Raniganj, followed by Barren Measure and Barakar. Mineral content is dominated by quartz (42–63%), siderite (9–15%) and clay (14–29%). Permian shales, in particular the Barren Measure, as inferred from the results of our study, demonstrate excellent properties of a potential shale gas system.     

Organic geochemistry and reservoir characterization of the organic matter-rich calcilutite in the Shulu Sag,Bohai Bay Basin,North China

Although extensive studies have been conducted on unconventional mudstone (shales) reservoirs in recent years, little work has been performed on unconventional tight organic matter-rich, fine-grained carbonate reservoirs. The Shulu Sag is located in the southwestern corner of the Jizhong Depression in the Bohai Bay Basin and filled with 400–1000 m of Eocene lacustrine organic matter-rich carbonates. The study of the organic matter-rich calcilutite in the Shulu Sag will provide a good opportunity to improve our knowledge of unconventional tight oil in North China. The dominant minerals of calcilutite rocks in the Shulu Sag are carbonates (including calcite and dolomite), with an average of 61.5 wt.%. The carbonate particles are predominantly in the clay to silt size range. Three lithofacies were identified: laminated calcilutite, massive calcilutite, and calcisiltite–calcilutite. The calcilutite rocks (including all the three lithofacies) in the third unit of the Shahejie Formation in the Eocene (Es₃) have total organic carbon (TOC) values ranging from 0.12 to 7.97 wt.%, with an average of 1.66 wt.%. Most of the analyzed samples have good, very good or excellent hydrocarbon potential. The organic matter in the Shulu samples is predominantly of Type I to Type II kerogen, with minor amounts of Type III kerogen. The temperature of maximum yield of pyrolysate (T_max) values range from 424 to 452 °C (with an average of 444 °C) indicating most of samples are thermally mature with respect to oil generation. The calcilutite samples have the free hydrocarbons (S₁) values from 0.03 to 2.32 mg HC/g rock, with an average of 0.5 mg HC/g rock, the hydrocarbons cracked from kerogen (S₂) yield values in the range of 0.08–57.08 mg HC/g rock, with an average of 9.06 mg HC/g rock, and hydrogen index (HI) values in the range of 55–749 mg HC/g TOC, with an average of 464 mg HC/g TOC. The organic-rich calcilutite of the Shulu Sag has very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The pores in the Shulu calcilutite are of various types and sizes and were divided into three types: (1) pores within organic matter, (2) interparticle pores between detrital or authigenic particles, and (3) intraparticle pores within detrital grains or crystals. Fractures in the Shulu calcilutite are parallel to bedding, high angle, and vertical, having a significant effect on hydrocarbon migration and production. The organic matter and dolomite contents are the main factors that control calcilutite reservoir quality in the Shulu Sag.     

Properties and shale oil potential of saline lacustrine shales in the Qianjiang Depression,Jianghan Basin,China

The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (R_o ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S₁ × 100/TOC, mg HC/g TOC and S₁, mg HC/g rock) and brittleness data demonstrate that the Eq3^3x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation.     

Evolution of porosity and pore types in organic-rich,calcareous, Lower Toarcian Posidonia Shale

Low and high resolution petrographic studies have been combined with mineralogical, TOC, RockEval and porosity data to investigate controls on the evolution of porosity in stratigraphically equivalent immature, oil-window and gas-window samples from the Lower Toarcian Posidonia Shale formation. A series of 26 samples from three boreholes (Wickensen, Harderode and Haddessen) in the Hils syncline was investigated. The main primary components of the shales are microfossiferous calcite (30–50%), clay minerals (20–30%) and Type II organic matter (TOC = 7–15%, HI = 630–720 mg/gC in immature samples). Characteristic sub-centimetric light and dark lamination reflects rapid changes in the relative supply of these components. Total porosities decrease from 10 to 14% at Ro = 0.5% to 3–5% at Ro = 0.9% and then increase to 9–12% at Ro = 1.45%. These maturity-related porosity changes can be explained by (a) the primary composition of the shales, (b) carbonate diagenesis, (c) compaction and (d) the maturation, micro-migration, local trapping and gasification of heterogeneous organic phases. Calcite undergoes dissolution and reprecipitation reactions throughout the maturation sequence. Pores quantifiable in SEM (>ca. 50 nm) account for 14–25% of total porosity. At Ro = 0.5%, SEM-visible macropores¹ are associated mainly with biogenic calcite. At this maturity, clays and organic matter are not visibly porous but nevertheless hold most of the shale porosity. Porosity loss into the oil window reflects (a) compaction, (b) carbonate cementation and (c) perhaps the swelling of kerogen by retained oil. In addition, porosity is occluded by a range of bituminous phases, especially in microfossil macropores and microfractures. In the gas window, mineral-hosted porosity is still the primary form of macroporosity, most commonly observed at the organic-inorganic interface. Increasing porosity into the gas window also coincides with the formation of isolated, spongy and complex meso- and macropores within organic particles, related to thermal cracking and gas generation. This intraorganic porosity is highly heterogeneous: point-counted macroporosity of individual organic particles ranges from 0 to 40%, with 65% of organic particles containing no macropores. We suggest that this reflects the physicochemical heterogeneity of the organic phases plus the variable mechanical protection afforded by the mineral matrix to allow macroporosity to be retained. The development of organic macroporosity cannot alone account for the porosity increase observed from oil to gas window; major contributions also come from the increased volume of organic micro- and meso-porosity, and perhaps by kerogen shrinkage.     

Origin of organic matter and paleoenvironment conditions of the Late Jurassic organic-rich shales from shabwah sub-basin (western Yemen): Constraints from petrology and biological markers

Late Jurassic organic-rich shales from Shabwah sub-basin of western Yemen were analysed based on a combined investigations of organic geochemistry and petrology to define the origin, type of organic matter and the paleoenvironment conditions during deposition. The organic-rich shales have high total sulphur content values in the range of 1.49–4.92 wt. %, and excellent source rock potential is expected based on the high values of TOC (>7%), high extractable organic matter content and hydrocarbon yield exceeding 7000 ppm. The high total sulphur content and its relation with high organic carbon content indicate that the Late Jurassic organic-rich shales of the Shabwah sub-basin were deposited in a marine environment under suboxic-anoxic conditions. This has been evidenced from kerogen microscopy and their biomarker distributions. The kerogen microscopy investigation indicated that the Late Jurassic organic-rich shales contain an abundant liptinitic organic matter (i.e., alginite, structureless (amorphous organic matters)). The presence of alginite with morphology similar to the lamalginite alga and amorphous organic matter in these shale samples, further suggests a marine origin. The biomarker distributions also provide evidence for a major contribution by aquatic algae and microorganisms with a minor terrigenous organic matter input. The biomarkers are characterized by unimodal distribution of n-alkanes, low acyclic isoprenoids compared to normal alkanes, relatively high tricyclic terpanes compared to tetracyclic terpanes, and high proportion of C₂₇ and C₂₉ regular steranes compared to C₂₈ regular sterane. Moreover, the suboxic to anoxic bottom water conditions as evidenced in these Late Jurassic shales is also supported based on relatively low pristane/phytane (Pr/Ph) ratios in the range of 0.80–1.14. Therefore, it is envisaged here that the high content of organic matter (TOC > 7 wt.%) in the analysed Late Jurassic shales is attributed to good organic matter (OM) preservation under suboxic to anoxic bottom water conditions during deposition.     

Characteristics and petroleum origin of the Carboniferous volcanic rock reservoirs in the Shixi Bulge of Junggar Basin,western China

Shixi Bulge of the central Junggar Basin in western China is a unique region that provides insight into the geological and geochemical characteristics of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks in the Shixi Bulge mainly consist of striped lava and agglomerate, as well as breccia lava and tight tuff. Volcanic rocks differ in porosity and permeability. Striped lava exhibits the highest porosity (average: 14.2%) but the lowest permeability (average: 0.67 × 10⁻¹⁵ m) among the rock types. Primary gas pores are widely developed and mostly filled. Secondary dissolution pores and fractures are two major reservoir storage spaces. Capillary pressure curves suggest the existence of four pore structure types of reservoir rocks. Several factors, namely, lithology, pore structure, and various diagenesis, govern the physical properties of volcanic rocks. The oil is characterized by a high concentration of tricyclic terpane, a terpane distribution of C₂₃ < C₂₁ > C₂₀, and sterane distributions of C₂₇ < C₂₈ < C₂₉ and C₂₇ > C₂₈ < C₂₉. Oil and gas geochemistry revealed that the oil is a mixture derived primarily from P₂w source rock and secondarily from P₁j source rock in the sag west of Pen-1 Well. The gases are likely gas mixtures of humic and sapropelic organic origins, with the sapropelic gas type dominant in the mixture. The gas mixture is most likely cracked from kerogen rather than oils. The Carboniferous volcanic reservoirs in Shixi Bulge share some unique characteristics that may provide useful insights into the various roles of different volcanic reservoir types in old volcanic provinces. The presence of these reservoirs will undoubtedly encourage future petroleum exploration in volcanic rocks up to the deep parts of sedimentary basins.     

Nano-scale pore structure and fractal dimension of organic-rich Wufeng-Longmaxi shale from Jiaoshiba area,Sichuan Basin: Investigations using FE-SEM,gas adsorption and helium pycnometry

Much attention have been recently paid to the upper Ordovician Wufeng shale (O₃w) and lower Silurian Longmaxi shale (S₁l) in the Jiaoshiba area of Sichuan Basin, which is now the largest producing shale gas field in China. Field emission scanning electron microscopy (FE-SEM), low pressure gas (N₂ and CO₂) adsorption, helium pycnometry, X-ray diffraction and geochemical analyses were performed to investigate the pore structure and fractal dimension of the pores in O₃w-S₁l shale formation in the Jiaoshiba area. FE-SEM images show that organic matter (OM) pores are dominant in the organic-rich samples and these pores are often irregular, bubble-like, elliptical and faveolate in shape, while in organic-poor samples, limited and isolated interparticle (interP), intraparticle (intraP) and OM pores are observed. Reversed S-shaped isotherms obtained from nitrogen adsorption are type Ⅱ, and hysteresis loops indicate that the shape of micropore in the samples is slit-or plate-like. BET surface areas and total pore volume vary from 12.2 to 27.1 m²/g and from 1.8 × 10⁻² to 2.9 × 10⁻² cm³/g, with an average of 19.5 m²/g and 2.3 × 10⁻² cm³/g, respectively. Adsorption volume from both N₂ and CO₂ adsorption increases with respect to TOC contents. Porosities obtained from helium porosimetry are comparable with these from gas (CO₂ and N₂) adsorption in O₃w-S₁l shale. However, porosity determined by quantitative FE-SEM analysis is much smaller, which is mainly related to limited resolution and the small areas of investigation.Based on the Frenkel-Halsey-Hill (FHH) model of low-pressure N₂ adsorption, fractal dimensions of the pores varied from 2.737 to 2.823. Relationships between pore structure parameters and TOC content, mineral composition and fractal dimension reveal that the fractal dimension is mainly associated with micropores. Samples with higher TOC content, higher quartz content and lower clay content tend to contain more heterogeneous micropores, resulting in higher fractal dimensions and more complicated pore structure in shales. Therefore, fractal dimension is an effective parameter to reflect the complexity of pore structure and the degree of micropore development in O₃w-S₁l shale.     

Enrichment and distribution of shale oil in the Cretaceous Qingshankou Formation,Songliao Basin,Northeast China

The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K₂qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K₂qn¹), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (T_max) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K₂qn¹ shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K₂qn¹ shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin.     

The Cenomanian/Turonian oceanic anoxic event in the Razzak Field, north Western Desert, Egypt: Source rock potential and paleoenvironmental association

The Western Desert of Egypt is one of the world’s most prolific Jurassic and Cretaceous hydrocarbon provinces. It is one of many basins that experienced organic-rich sedimentation during the late Cenomanian/early Turonian referred to as oceanic anoxic event 2 (OAE2). The Razzak #7 oil well in the Razzak Field in the northern part of the Western Desert encountered the Upper Cretaceous Abu Roash Formation. This study analyzed 23 samples from the upper “G”, “F”, and lower “E” members of the Abu Roash Formation for palynomorphs, particulate organic matter, total organic carbon (TOC) and δ¹³C_org in order to identify the OAE2, determine hydrocarbon source rock potential, and interpret the depositional environment. The studied samples are generally poor in palynomorphs, but show a marked biofacies change between the lower “E” member and the rest of the studied samples. Palynofacies analysis (kerogen quality and quantity) indicates the presence of oil- and gas-prone materials (kerogen types I and II/III, respectively), and implies reducing marine paleoenvironmental conditions. Detailed carbon stable isotopic and organic carbon analyses indicate that fluctuations in the δ¹³C_org profile across the Abu Roash upper “G”, “F”, and lower “E” members correspond well with changes in TOC values. A positive δ¹³C_org excursion (∼2.01‰) believed to mark the short-term global OAE2 was identified within the organic-rich shaly limestone in the basal part of the Abu Roash “F” member. This excursion also coincides with the peak TOC measurement (24.61 wt.%) in the samples.     

Source rock characteristics and hydrocarbon generation modelling of Upper Cretaceous Mukalla Formation in the Jiza-Qamar Basin,Eastern Yemen

The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis T_max in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S₂) pyrograms with n-alkane/alkene doublets extending beyond nC₃₀. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m² to 70.0 mW/m² and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m² at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.     

Depositional environment of oil shale within the Eocene Jijuntun Formation in the Fushun Basin (NE China)

The non-marine Fushun Basin in NE China is a fault-controlled basin filled with Eocene sediments. It hosts the largest opencast coal and oil shale mine in Asia. A single thick oil shale layer overlying sub-bituminous coal occurs within the Middle Eocene Jijuntun Formation. Based on mineralogy, inorganic and organic geochemistry, organic petrography, stable isotope geochemistry, and vitrinite reflectance measurements, the depositional environment and the oil shale potential of the oil shale-bearing succession were investigated. The Jijuntun Formation is subdivided into a lower and an upper unit characterized by a low and high quality oil shale, respectively. The thick oil shale layer of the Jijuntun Formation developed under long-lasting stable conditions in a deep freshwater lake, after drowning of a swamp. The organic matter in the lower unit is characterized by landplant-derived macerals. The sediments containing a type II kerogen (HI: ∼400 mgHC/gTOC) were deposited during warm and humid conditions. Lacustrine organisms predominant in the upper unit are forming kerogen type I (HI: ∼700 mgHC/gTOC). High bioproductivity and excellent preservation conditions resulted in high TOC contents up to 23.6 wt.% in the upper unit. The organic matter preservation was controlled by photic zone anoxia originating in a temperature stratified water column in the deep lake, without significant changes in bottom water salinity. Mid-Eocene cooling during deposition of the upper unit of the Jijuntun Formation is reflected by clay mineral composition. A hot and arid climate favoring brackish conditions in a shallow lake prevailed during accumulation of the overlying carbonate-rich Xilutian Formation. Individual geochemical parameters in the Fushun Basin have to be used with caution, e.g. the maturity proxy T_max is affected by kerogen type, the redox proxy Pr/Ph ratio is probably biased by different sources of isoprenoids. This demonstrates the importance of multi-proxy studies.     

Respiration,mineralization, and biochemical properties of the particulate matter in the southern Nansen Basin water column in April 1981

Determinations of the activity of the respiratory electron transport system (ETS), during the FRAM III expedition permit us to estimate oxygen utilization rates (R_O2) from the surface to 2000 m under the polar pack ice in the Nansen Basin just north of Svalbard (83°N, 7°E) during April 1981. We found R_O2 at in situ temperatures ranging from 20 pM O₂ min⁻¹ just below the ice to 0.2 pM O₂ min⁻¹ at 2000 m. These rates are low compared to most other ocean regions, but they could decrease particulate organic carbon and nitrogen by 76% and 74%, respectively, over a period of ∼6 months. The R_O2 calculations based on measurements made at 0 °C yielded a power function of R_O2 vs. depth (Z) of R_O2=67Z^−0.5534. When this R_O2 profile was superimposed on a more recent oxygen utilization rate profile made using the ³He–³H–AOU method (OUR), in the same vicinity of the Nansen Basin during 1987 (OUR=52Z^–0.4058, [Zheng, Y., Schlosser, P., Swift, J.W., Jones, E.P., 1997. Oxygen utilization rates in the Nansen Basin, Arctic Ocean: implications for new production. Deep Sea Research I 44, 1923–1943]), the agreement of the two profiles was close. On one hand, this was to be expected because R_O2 is the biological basis of OUR, on the other hand, it was a surprise because the methodologies are so different. Nitrate mineralization obtained from ETS activities also compared favorably with calculations based on the data of Zheng et al. [1997. Oxygen utilization rates in the Nansen Basin, Arctic Ocean: implications for new production. Deep Sea Research I 44, 1923–1943]. Chlorophyll ranged from 6 ng L⁻¹ at 5 m to 0.06 ng L⁻¹ at 2000 m. Particulate organic carbon (POC) decreased from 0.93 μM C just below the ice to less than 0.4 μM C at 500 m. Particulate organic nitrogen (PON) was not detectable below 70 m, however in the upper 70 m it ranged from 0.16 to 0.04 μM N. The C/N mass ratio over these depths ranged from 5.8 to 11.3. Annual carbon productivity as calculated to balance the total water column respiration was 27 g C m⁻² y⁻¹. The integrated respiration rate between 50 and 4000 m suggests that exported production and carbon flux from the 50 m level was 24 g C m⁻² y⁻¹. These are minimal estimates for the southern Nansen Basin because they are based on measurements made at the end of the Arctic winter.     

Pore structure characteristics of tight sandstones in the northern Songliao Basin,China

Understanding the pore structure characteristics of tight gas sandstones is the primary purpose of reservoir evaluation and efforts to characterize tight gas transport and storage mechanisms and their controls. Due to the various pore types and multi-scale pore sizes in tight reservoirs, it is essential to combine several techniques to characterize pore structure. Scanning electron microscopy (SEM), nitrogen gas adsorption (N₂GA), mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) were conducted on tight sandstones from the Lower Cretaceous Shahezi Formation in the northern Songliao Basin to investigate pore structure characteristics systematically (e.g., type and size distribution of pores) and to establish how significant porosity and permeability are for different pore types. The studied tight sandstones are composed of intergranular pores, dissolution pores and intercrystalline pores. The integration of N₂GA and NMR can be used as an efficient method to uncover full pore size distribution (PSD) of tight sandstones, with pore sizes ranging from 2 nm to dozens of microns. The full PSDs indicate that the pore sizes of tight sandstones are primarily distributed within 1.0 μm. With an increase in porosity and permeability, pores with larger sizes contribute more to porosity. Intercrystalline pores and intergranular/dissolution pores can be clearly distinguished on the basis of mercury intrusion and surface fractal. The relative contribution of intercrystalline pores to porosity ranges from 58.43% to 91.74% with an average of 79.74%. The intercrystalline pores are the primary contributor to pore space, whereas intergranular/dissolution pores make a considerably greater contribution to permeability. A specific quantity of intergranular/dissolution pores is the key to producing high porosity and permeability in tight sandstone reservoirs. The new two permeability estimation models show an applicable estimation of permeability with R² values of 0.955 and 0.962 for models using D_max (pore diameter corresponding to displacement pressure) and D_f (pore diameter at inflection point), respectively. These results indicate that both D_max and D_f are key factors in determining permeability.     

Characterization of shale pore system: A case study of Paleogene Xin'gouzui Formation in the Jianghan basin,China

The pore size classification (micropore <2 nm, mesopore 2–50 nm and macropore >50 nm) of IUPAC (1972) has been commonly used in chemical products and shale gas reservoirs; however, it may be insufficient for shale oil reservoirs. To establish a suitable pore size classification for shale oil reservoirs, the open pore systems of 142 Chinese shales (from Jianghan basin) were studied using mercury intrusion capillary pressure analyses. A quantitative evaluation method for I-micropores (0–25 nm in diameter), II-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (>1000 nm) within shales was established from mercury intrusion curves. This method was verified using fractal geometry theory and argon-ion milling scanning electron microscopy images. Based on the combination of pore size distribution with permeability and average pore radius, six types (I-VI) shale open pore systems were analyzed. Moreover, six types open pore systems were graded as good, medium and poor reservoirs. The controlling factors of pore systems were also investigated according to shale compositions and scanning electron microscopy images. The results show that good reservoirs are composed of shales with type I, II and III pore systems characterized by dominant mesopores (mean 68.12 vol %), a few macropores (mean 7.20 vol %), large porosity (mean 16.83%), an average permeability of 0.823 mD and an average pore radius (r_a) of 88 nm. Type IV pore system shales are medium reservoirs, which have a low oil reservoir potential due to the developed II-micropores (mean 57.67 vol %) and a few of mesopores (mean 20.19 vol %). Poor reservoirs (composed of type V and VI pore systems) are inadequate reservoirs for shale oil due to the high percentage of I-micropores (mean 69.16 vol %), which is unfavorable for the flow of oil in shale. Pore size is controlled by shale compositions (including minerals and organic matter), and arrangement and morphology of mineral particles, resulting in the developments of shale pore systems. High content of siliceous mineral and dolomite with regular morphology are advantage for the development of macro- and mesopores, while high content of clay minerals results in a high content of micropores.     

Stable isotopes of carbon and nitrogen in suspended matter and sediments from the Godavari estuary

Spatial distribution of the carbon and nitrogen content and their isotopic enrichment in suspended matter and sediments were measured in the Godavari estuary to identify the sources and transformation mechanism of organic matter. Significant variability in isotopic distribution was found over the entire length of the Godavari estuary, suggesting multiple sources of organic matter. The mean isotopic ratios (δ¹³C_sed −25.1 ± 0.9, δ¹³C_sus −24.9 ± 1, δ¹⁵N_sed 8.0 ± 2 and δ¹⁵N_sus 6.5 ± 0.9‰) and elemental concentrations (C_sed 0.45 ± 0.2%, C_sus 0.9 ± 0.7%, N_sed 0.07 ± 0.05% and N_sus 0.16 ± 0.1%) support a predominantly terrigenous source. Significant enrichment in the isotopic ratios of δ¹³C from the upper to lower estuary in both suspended (−27.5 and −24.3‰, respectively) and sedimentary (−26.2 and −24.9‰, respectively) phases indicates a decrease in the influence of terrigeneous material toward the mouth of the estuary. A significant positive relationship exists between the δ¹³C of suspended and sediment, which indicates that these two organic carbon pools are likely coupled in the form of a significant exchange between the two phases. A positive relationship exists between chlorophyll a and suspended organic matter, which may mean that a significant source of organic carbon is the in situ produced phytoplankton. But, applying a simple mixing model to our isotopes, data yielded about 46% as the contribution of the terrestrial source to suspended matter, which may support the excessive heterotrophic activity in the Godavari estuary reported earlier.     

The sources and accumulation rate of sedimentary organic matter in the Pearl River Estuary and adjacent coastal area, Southern China

In this study, the contents, sources and accumulation rate of sedimentary organic matter (OM) in the Pearl River Estuary (PRE) and adjacent coastal area were investigated. The stable carbon isotopic composition (δ¹³C) is a reliable geochemical proxy and was used to indicate the OM origin here. Nevertheless, the organic carbon and nitrogen molar ratios (TOC/TN) and the stable nitrogen isotopic composition (δ¹⁵N) were affected by diagenesis and could be the supplementary indicators. The sources of OM were estimated based on the two end-member model. The results showed that in the estuary, sedimentary OM originated from terrestrial and aquatic mixing origins, whereas, OM in coastal sediments was dominantly algae-derived. The accumulation rate of sedimentary OM was analyzed based on ²¹⁰Pb dating. Due to the sampling sites and the distinct hydraulic environments, the accumulation rates of TOC, aquatic and terrestrial OC were obviously higher in the estuary than in coastal area. TOC accumulation rates were 18–27 mg cm⁻² y⁻¹ in the estuary, and 0.84–3.6 mg cm⁻² y⁻¹ in coastal area. Aquatic OC accumulation rates were 7.9–11.3, 0.8–1.3, and 2.6–3.1 mg cm⁻² y⁻¹, and terrestrial OC accumulation rates were 9.7–16.3, 0.02–0.14, 0.16–0.42 mg cm⁻² y⁻¹ in cores 2, 5, 6, respectively. It could be seen from the high accumulation rate of organic matter in the estuary that, when nutrients increased in the river, phytoplankton biomass and productivity would also have increased. As a result, phytoplankton sinking and organic matter sedimentation usually increased with primary productivity, resulting in the observed accumulation rate of aquatic OC in the estuary. Furthermore, terrestrial OC accumulation rates in the estuary and coastal area showed an increasing trend with the age.     

Late Cretaceous (Late Turonian,Coniacian and Santonian) petroleum source rocks as part of an OAE,Tarfaya Basin,Morocco

Late Turonian, Coniacian and Santonian source rock samples from a recently drilled well (Tafaya Sondage No. 2; 2010) in the Tarfaya Basin were analyzed for quantity, quality, maturity and depositional environment of the organic matter (OM). To our knowledge such a thick sequence of organic matter-rich Turonian to Santonian source rocks was investigated in that great detail for the first time. Organic geochemical and organic petrological investigations were carried out on a large sample set from the 200 m thick sequence. In total 195 core samples were analyzed for total organic carbon (C_org), total inorganic carbon contents and total sulfur (TS) contents. Rock-Eval pyrolysis and vitrinite reflectance measurements were performed on 28 samples chosen on the basis of their C_org content. Non-aromatic hydrocarbons were analyzed on selected samples by way of gas chromatography–flame ionization detection (GC–FID) and GC–mass spectrometry (GC–MS). The organic matter-rich carbonates revealed a high source rock potential, representing type I kerogen and a good preservation of the organic matter, which is mainly of marine (phytoplankton) origin. HI values are high (400–900 mg/g C_org) and in a similar range as those described for more recent upwelling sediments along the continental slope of North Africa. TS/C_org ratios as well as pristane over phytane ratios indicate variable oxygen content during sediment deposition. All samples are clearly immature with respect to petroleum generation which is supported by maturity parameters such as vitrinite reflectance (0.3–0.4%), T_max values (401–423 °C), production indices (S₁/(S₁ + S₂) > 0.1) as well as maturity parameters based on ratios of specific steranes and hopanes.     

Could the conventionally known Abu Roash “G” reservoir (upper Cenomanian) be a promising active hydrocarbon source in the extreme northwestern part of Egypt? Palynofacies,palaeoenvironmental, and organic geochemical answers

In different areas of the Western Desert of Egypt, the Abu Roash “G” Member exhibits either a reservoir or source affinity. Thus, thirteen cutting samples covering the Abu Roash “G” Member were selected from the Nest-1A well at Matruh Basin to investigate its hydrocarbon source potential. Palynological age dating of the section that is calibrated with foraminifera and ostracodes enabled a proper identification of the “G” Member. Detailed analysis of the vertical distribution of particulate organic matter of this member shows two palynofacies types. PF-1 reflects an outer middle shelf depositional environment of prevailed reducing (suboxic-anoxic) conditions for the organic-rich shales of the lower “G” Member (samples 1–8). While, PF-2 reflects a minor regression that resulted in deposition of another organic-rich shales of the upper “G” Member (samples 9–13) in an inner middle shelf setting under the same prevailing reducing (suboxic-anoxic) conditions.Organic geochemical analysis reveals good to very good potential of the “G” Member as a hydrocarbon source rock (1.8–2.41, avg. 2.15 total organic content wt %). It also shows good to very good petroleum potential (PP: 4.8–11 , avg. 8 mg HC/g rock). Pyrolsis and palynofacies analyses show kerogen type II for the lower “G” Member (samples 1–8), which is characterized by high Hydrogen index (HI: 396 and 329 mg HC/g TOC at depths 1500 and 1560 m) and very high dominance of oil-prone material (amorphous organic matter “AOM”, marine palynomorphs, and sporomorphs) and very rare occurrence of gas-prone material (brown phytoclasts). The upper “G” Member (samples 9–13) shows kerogen type II-III, which is characterized by a lower HI value of 213 mg HC/g TOC at depth 1340 m and it contains fewer amounts of gas-prone material and relatively lower AOM and marine palynomorphs in comparison to the upper “G” Member. Maturation parameters T_max (430–433 °C), production index (PI: 0.1 mg HC/g rock), and thermal alteration index (TAI: 2+) indicate the lower “G” Member has already entered the early oil-window kitchen, and it is expected to produce oil. The upper “G” Member is expected to produce only oil with no gas shows, because it is marginally mature (T_max 426 °C, PI 0.2, TAI 2). The source potential index (SPI: 5.3 t HC/m²) of the “G” Member shows it as currently generating moderate quantities of oil in the area of Nest-1A well.Consequently, the organic-rich shales of the “G” Member are suggested here as a promising, active oil source rock in that extreme northwestern part of the Western Desert of Egypt. However, for commercial oil recovery from the Abu Roash “G” Member, it is highly recommended to explore the depocentre of Matruh Basin at about 150 km east the Nest-1A well.     

Petroleum generation characteristics of heterogeneous source rock from Chia Gara formation in the Kurdistan region,northern Iraq as inferred by bulk and quantitative pyrolysis techniques

This study is the first attempt which provides information regarding the bulk and quantitative pyrolysis results of the Chia Gara Formation from the Kurdistan region, northern Iraq. Ten representative early-mature to mature samples from the Chia Gara Formation were investigated for TOC contents, Rock Eval pyrolysis, pyrolysis-GC and bulk kinetic parameters. These analyses were used to characterize the petroleum generated during thermal maturation of the Chia Gara source rock and to clarify the quantity of the organic matter and its effect on the timing of petroleum generation.Pyrolysis HI data identified two organic facies with different petroleum generation characteristics; Type II–III kerogen with HI values of >250 mg HC/g TOC, and Type III kerogen with HI values < 100 mg HC/g TOC. These types of kerogen can generate liquid HCs and gas. This is supported by the products of pyrolysis–gas chromatography (Py–GC) analysis of the extracted rock samples. Pyrolysis products show a dominance of a marine organic matter with variable contributions from terrestrial organic matter (Types II–III and III kerogen), and produces mainly paraffinic-naphthenic-aromatic low wax oils with condensate and gas.Bulk kinetic analysis of the Chia Gara source rock indicates a heterogeneous organic matter assemblage, typical of restricted marine environments in general. The activation energy distributions reveal relatively broad and high values, ranging from 40 to 64 kcal/mol with pre-exponential factors varying from 2.2835 E+12/sec to 4.0920 E+13/sec. The predicted petroleum formation temperature of onset (TR 10%) temperatures ranges from 110 to 135 °C, and peak generation temperatures (geological T_max) between 137 °C and 152 °C. The peak generation temperatures reach a transformation ratio in the range of 42–50% TR, thus the Chia Gara source rock could have generated and expelled significant quantities of petroleum hydrocarbons in the Kurdistan of Iraq.