Oil-prone Organic Matter Research Articles

The effects of sample preparation on the interpretation of pyrolysis-based organic matter analysis in immature oil shale

Oil shale as well as shale oil and shale gas are significant energy resources with huge reserves present in different parts of the world. Various geochemical proxies have been applied to assess the petroleum potential of oil shales with samples pre-treated in various ways, e.g. as whole rock or demineralized sample or as solvent extracted rock/kerogen. In this respect, it is important to understand and quantify, how achieved geochemical parameters are influenced by pre-treatment. In this study, a systematic comparison is presented based on a study on i) whole rock, ii) extracted whole rock, iii) kerogen concentrate, and iv) extracted kerogen concentrate obtained after solvent extraction of demineralized shales. In total, seven immature, organic matter-rich samples from the Miocene lacustrine sediments of the Nördlinger Ries impact crater, Germany, were pretreated in this way leading to overall 28 samples. A set of elemental analysis (C, H, N), Rock-Eval pyrolysis, and Curie Point-pyrolysis–gas chromatography–mass spectrometry measurements were performed on these pretreated samples. Mineral matter removal leads to significant increase of total organic carbon, but also thermally evaporable and pyrolytically cracked organic matter (Rock-Eval S1 and S2 peaks). To some extent, labile organic matter represented in the original S2 peak can be destructed by mineral removal with hydrochloric and hydrofluoric acid, as shown by elevated values of PI [S1/(S1 + S2)] after demineralization. The organic matter type tends to be more petroleum-prone with raised hydrogen index (HI) and aliphaticity values after demineralization, while Rock-Eval Tmax values commonly applied as parameters for thermal maturity tend to decrease, though not for all samples.Reduced TOC, S1, S2 and PI values of extracted samples suggest that both thermally evaporable and additionally some non-evaporable but soluble organic matter hidden in the original S2 peak can be lost after solvent extraction. Increased values of HI, H/C and N/C of extracted samples indicate more oil-prone organic matter types than unextracted samples. Typical maturity-related parameters such as aliphaticity and Rock-Eval Tmax decrease. Smectite and zeolites, which are abundant in the samples, are suggested to protect organic matter to some extent against solvent extraction, influencing a variety of geochemical proxies and the occurrence of metal cation-containing minerals. Zeolite invigorates the protection effect.

Depositional environments and source rock potential of some Upper Palaeozoic (Devonian) coals on Bjørnøya, Western Barents shelf

Upper Palaeozoic strata are potential sources for hydrocarbon plays on the Norwegian Barents Shelf. The island of Bjørnøya (Bear Island) is located on the western margin of the Barents Shelf and represents an exposed part of the Stappen High, which makes it an excellent location to investigate the source rock potential of this succession. Here, we investigate the organic geochemical composition and source rock potential of coals and organic-rich mudstones of Late Devonian to middle Permian ages. The thermal maturity of the analysed samples ranges from mature to overmature with some samples being in the late oil generation window, and thus exhibiting higher maturities than age and facies equivalent strata in central Spitsbergen in the NW corner of the Barents Shelf and on the Finnmark Platform to the south. The high maturities and thermal cracking may thus have negatively affected the applied isoprenoid and biomarker-based source facies parameters, which potentially inhibit correct source facies interpretation. However, our results and comparisons with previous studies indicate that the vitrinite- and inertinite-dominated humic coals occurring in the lower part of the succession formed by the accumulation of peat in fluvially-influenced, humid wetlands at paleo-equatorial latitudes during a pronounced episode of rifting in the Late Devonian (Famennian) to earliest Carboniferous (Mississippian). Our source rock evaluation indicates a good potential for liquid hydrocarbon generation for the coals of the Upper Devonian Røedvika Formation prior to maturation. The oil-prone organic matter of these coals is primarily considered as terrestrial and non-aqueous. Because of renewed rifting in the middle Carboniferous combined with a shift to arid climatic conditions, as well as an environmental change from dominantly terrestrial and marginal marine clastic to marine carbonate platform environments, the accumulation of wetland peats effectively came to an end. Thus, the overlying Carboniferous and Permian strata generally seems to yield poor to no hydrocarbon generation potential.

Organic geochemical heterogeneity of cretaceous mudrocks and reassessment of oil sources in the Tano Basin, Ghana

The Tano Basin in Ghana, situated within the South Atlantic margin, is a significant area for petroleum exploration. Previous studies have recognized the presence of source rocks rich in organic matter from the Cretaceous period in this basin. However, the specific origins of this organic matter, as well as the thermal maturity and depositional environment of the Cretaceous source strata, are not well characterized in existing literature. Here, geochemical data are reported on the bulk geochemical composition of 45 Maastrichtian to Albian-aged rock cuttings via pyrolysis and total organic carbon (TOC) analysis. Out of these samples, 29 were selected for further biomarker and stable carbon isotope (δ13C) analysis. The biomarker and isotopic signatures of the 29 rock extracts and 6 crude oils from the basin's productive Jubilee and TEN oil fields were compared to establish oil-oil and oil-source correlations. The Cenomanian and Turonian source rocks showed the greatest oil generation potential based on current bulk geochemical analysis. These rocks are dominated by oil-prone organic matter and are at a more favorable maturity stage compared to the Maastrichtian, Santonian, and Coniacian (M-S-C) rock suites. In contrast, the Albian rock samples, characterized by mixed Type II/III and Type III kerogen, and their high thermal maturity, indicate a high potential for the generation of gaseous hydrocarbons. The biomarker and isotope data from the Cenomanian, Turonian, and Albian (T-C-A) source rocks suggest that they were deposited in a Transitional Marine-Lacustrine environment characterized by reducing redox conditions. This environment effectively preserved organic matter from diverse sources such as bacteria, algae, and higher plants. Furthermore, biomarker ratios indicated that the T-C-A source rocks are in the early-peak mature window. On the other hand, the M-S-C source rocks appear to have been deposited under suboxic conditions in a Coastal Marine environment. Lower aquatic organisms dominate these rocks, which have an immature to marginally mature level. The analysis of lower molecular weight hydrocarbons (≤C20), characterized by an unresolved complex mixture, did not reveal any obvious correlation between the oils and the Cretaceous source rocks. However, the analysis of higher molecular weight hydrocarbons (≥C20) and isotopic ratios indicated that the commercial discoveries in the Jubilee and TEN fields share a genetic similarity and are primarily sourced from the T-C-A source rocks. Furthermore, the molecular and isotopic characteristics suggest that the M-S-C source rocks do not appear to have contributed to the oils found in the Jubilee and TEN fields. These new geochemical findings shed light on the paleoenvironmental conditions and source rock characteristics of the region, significantly contributing to our understanding of the petroleum evolution and potential of the Tano Basin.

Organic petrographic, geochemical, and sequence stratigraphic analyses for evaluating the hydrocarbon potential of Middle Jurassic–Lower Cretaceous rocks in Shushan Basin, northwestern Egypt

Integrated organic petrographic and geochemical analyses were made on organic-rich marine carbonate and mixed clastic-carbonate rocks of Middle–Late Jurassic and Early Cretaceous age from the Shushan Basin, Egypt to evaluate their hydrocarbon potential. Analyses allowed the identification of depositional settings, paleoclimate, and three third order genetic stratigraphic sequences (SQ) with deposits assigned to highstand (HST), lowstand (LST) and transgressive systems tracts (TST). Deposition of the source rocks in the rifting Shushan Basin resulted from the interaction between Neotethyan sea level changes, tectonic, and climate. The good reducing conditions developed during the Neotethyan Middle–Late Jurassic (Bajocian–Kimmeridgian) second order sea level rises and the climatically induced carbonate sedimentation resulted in the deposition of the organic-rich carbonates of the Khatatba Formation (SQ 1, early–middle TST) in inner–middle shelf settings under anoxic–dysoxic conditions. The Late Jurassic (late Kimmeridgian) uplifting resulted in the deposition of the organic-lean mixed clastic–carbonate strata of the Masajid Formation (SQ 1, latest TST) in the same shelfal and reducing conditions, which experienced a notable dilution of organic matter. The late TST deposits of SQ 1 are good to very good oil-producing source rocks, where they show average good to very good generative potential of late mature (late oil-to early wet gas-window) highly oil-prone organic matter. The Early Cretaceous (Valanginian–Albian) uplifting associated with the rifting of the Shushan Basin overprinted the Neotethyan late Valanginian–Hauterivian second order sea level rises, Aptian second order highstand sea level, and Albian second order sea level rise. The coeval climatic shift toward more humid conditions resulted in the clastic-dominated deposition of the organic-lean regressive units of SQ 2 (HST and LST of Alam El Bueib, Alamein, and Dahab formations) and SQ 3 (HST and LST of the lower–upper Kharita Formation) in marginal marine settings under anoxic–dysoxic to oxic conditions. The HST and LST deposits of the SQ 2 and SQ 3 show poor to good organic richness of early–mid mature (early–peak oil-window) oil/gas-prone and gas/oil-prone organic matter, respectively and exhibit average fair oil source rock potential with no gas generation.

Thermal maturity assessment of marine source rocks integrating Raman spectroscopy, organic geochemistry and petroleum systems modeling

A core sample set, comprising twenty-eight carbonaceous mudrocks from ten exploration wells was analysed by standard organic geochemical methods (programmed pyrolysis, elemental analysis) and a novel Raman spectroscopic technique. The kerogen of the studied rocks is classified as amorphous marine, sulfur-rich, oil-prone organic matter with predominantly algal precursor material. The sample set covers a wide range of thermal maturation from premature to late mature. Hydrogen index, Tmax and atomic H/C ratios vary from 52 to 708 mg HC/g rock, from 426 to 488 °C, and from 0.58 to 1.35, respectively. Raman spectral features, expressed as Raman band separation (RBS), correlate with geochemical maturity parameters and with results from basin modeling. The combined use of independent maturity parameters, like programmed pyrolysis, elemental analysis and Raman spectroscopy, improves the calibration of a regional basin model in the Eastern Arabian Basin, where direct maturity measurements from vitrinite reflectance are deficient.

Discovery of a new source-rock interval within the Pantokrator Formation, Ionian Zone, western Greece: Insights from sulfur speciation and kinetics analyses

The Ionian Zone in western Greece constitutes a Mesozoic sedimentary basin with petroleum potential. Numerous rock intervals with source, reservoir, and seal properties, along with several surface oil seeps have been identified. These rocks are linked to the northern portion of the Ionian Zone in nearby Albania, where similar rocks host oil and gas fields. This study describes a newly discovered source rock interval, the “Pantokrator Shales”, which lies within the Pantokrator Carbonates Fm, between the Rhaetian platform dolomite (“Pantokrator Dolomites” Fm.) and the lower Liassic platform limestone (“Pantokrator Limestones” Fm.) sequence. This interval is an important source rock for the petroleum system of the Ionian Zone in western Greece and Albania. The samples were acquired from outcrops and subsequently examined by programmed pyrolysis and organic petrography, as well as for sulfur speciation. The Pantokrator Shales Formation is comprised of ∼30 m of organic-rich shales alternating with less organic-rich light gray and thin-grained dolomitic sandstones and dolomite beds. The results of organic geochemical and organic petrographic analyses suggest high amounts (up to 38.68 wt% TOC) of Type I and mixed II/II-S organic matter with high generation potential (S1+S2 is up to 269.79 mg HC/g and HI of up to 790 mg HC/g TOC). Selected intervals analyzed have large amounts of labile organic sulfur. Pyrolysis Organic Sulfur (POS) ranges between 1.22 and 4.87 wt% on a whole-rock basis, with Sulfur Index (SI) values ranging from 116 to 174 (minimum SI for Types IS and IIS = 100), suggesting that the kerogen has already entered the oil window and generated liquid hydrocarbons in accordance with reflectance values measured on vitrinite (%VR: 0.60–0.65) and/or solid migrabitumens. Widespread conditions that favored the deposition and preservation of high amounts of oil-prone organic matter (including vulcanization processes of organic matter) existed locally in the basin during the Late Triassic to Early Liassic. This study showed that the stratigraphic position, the lateral and vertical extent, the organic matter quantity and quality, as well as the sulfur (S) content of the Pantokrator Shales, are comparable to intervals in nearby Albania, Sicily and the Italian peninsula. The high clastic input that was recorded may be associated with a regional shift in climatic conditions towards more seasonably controlled wetter conditions, as inferred from adjacent areas.

Origins and deep petroleum dynamic accumulation in the southwest part of the Bozhong depression, Bohai Bay Basin: Insights from geochemical and geological evidences

Latest exploration practices revealed appreciable petroleum resources in the deep pre-Cenozoic reservoirs in the southwest area of the Bozhong depression; however, the origins and accumulation mechanisms of deep hydrocarbons remain not fully understood. Here, an integrated study of the geochemical characteristics of overlying source rocks, maturity evaluation of petroleum, and origin of natural gas was conducted to characterize the dynamic petroleum accumulation and illustrate the main factors influencing the differential phases of petroleum distribution in the research area. The third member of the Dongying Formation (Ed3) mudstone in the research area displays high organic richness and is characterized by oil-prone organic matter, indicating high petroleum potential. The oils contained in the CFD18 and BZ13 buried-hill traps were mainly derived from the Ed3 and Shahejie Formation (Es) source rocks, respectively, with natural gas of kerogen cracking origin. Buried-hill oil from the BZ13 field displays a high thermal maturity than that of the CFD18 oils, which was evidenced by maturity parameters of saturated and aromatic hydrocarbons and concentrations of stigmastane. Nevertheless, maturity index of diamondoids and carbon isotopic composition of natural gas indicate the possible presence of mixing of higher mature Es fluids for the CFD18 field. This research underlines the contribution of the overlapped effective source rocks to the buried-hill traps. The causes of multiple petroleum phases in the deep reservoirs in the research area are mainly linked to dynamic petroleum accumulation rather than source rock type and oil secondary cracking. Although faults are present to act as vertical migration conduits due to late-stage activation with high intensity, abundant petroleum supply due to near-source charge and favorable constitution relationship of source rock and reservoir rock provide crucial conditions for deep petroleum accumulation in a tectonic activation zone.

Organic geochemical heterogeneity of the Cretaceous Abu Gabra Formation and reassessment of oil sources in the Sufyan sub-basin, Sudan

The Lower Cretaceous Abu Gabra Formation (AG) is considered to contain the major source rocks in the Sufyan sub-basin, Sudan. Although prior studies have established the presence of organic-rich lacustrine mudstones, the geochemical heterogeneity of organic facies, thermal maturity, and molecular nature of individual members of the Abu Gabra Formation are insufficiently characterized for oil-source rock correlation. Here, we report on geochemical analysis of 228 cutting samples utilizing Rock-Eval pyrolysis and TOC measurements, from which twenty samples were chosen for investigation of saturated biomarkers. The well cutting samples are from four members (AG1, AG12, AG22 and AG3) comprising the Abu Gabra Formation. These analyses were compared to eleven oils produced from the Abu Gabra sandstones to establish member-specific oil-source correlation. The AG22 and AG3 members have the greatest source potential, containing a higher content of oil-prone organic matter and more favorable maturity than those of the AG12 and AG1 members. Biomarker data for the AG22 and AG3 source rocks indicate that deposition occurred under a moderately stratified and somewhat saline water column with a predominance of algal/bacterial input (Type I kerogen). The AG22 and AG3 source rocks have entered the window of oil generation. In contrast, the AG1 and AG12 source rocks were possibly deposited in fresh to slightly saline water conditions, have a greater input of terrigenous organic matter input, and are immature to marginally mature. Oil-oil and oil-source rock correlations suggest that the crude oils in the Sufyan sub-basin are genetically homogenous, belong to a single oil family, and are mainly derived from the AG22 and AG3 source rocks. Contribution from the AG1 and AG12 source rocks is not apparent from the molecular distributions and is considered to be negligible. The current study provides valuable guidance of source rock evaluation and oil-source rock correlation, which can be a benefit to future petroleum exploration work in the Sufyan sub-basin.

Identification of effective source rocks in different sedimentary environments and evaluation of hydrocarbon resources potential: A case study of paleogene source rocks in the Dongpu Depression, Bohai Bay Basin

Source rocks in lacustrine rifting basins have great heterogeneity, which leads to imprecise assessments of hydrocarbon resources. Previous studies evaluated the source rocks of different sedimentary environments in lacustrine basins or depressions using the same lower limit of effective source rocks (i.e., the minimum total organic carbon (TOC) at which the source rocks are capable of expelling hydrocarbons). In this study, the source rock samples were selected from five formations in the Dongpu Depression for organic geochemical experiments and quantitative simulations of hydrocarbon expulsion. According to salinity differences, every formation was divided into a saline area, transition area and freshwater area. The results show that the maximum thickness of source rocks developed in the saline and transition areas is 700 m. Additionally, source rocks with a higher TOC and oil-prone organic matter types (II1 and II2) also develop in the saline and transition areas, and most have entered the mature stage. The TOC values corresponding to the lower limit of effective source rocks in the saline, transition, and freshwater areas are 0.3%, 0.4% and 0.5%, respectively. Furthermore, the hydrocarbon expulsion ratio (amount of hydrocarbon discharged per unit of TOC from the source rocks) for the freshwater area is 253.1 mg/g, while the ratios in the saline and transition areas are relatively higher at 439.4 mg/g and 369.3 mg/g, respectively. The hydrocarbon expulsion rate (change in the expulsion ratio per unit thermal evolution degree) and hydrocarbon expulsion efficiency (ratio of cumulative hydrocarbon expulsion amount to generation amount) in the saline, transition and freshwater areas present maxima when the Ro (vitrinite reflectance) values are 0.95%, 0.85% and 0.82%, respectively. The hydrocarbon expulsion quantities in the saline, transition and freshwater areas account for 24%, 49% and 27% of the total, respectively. Therefore, the main hydrocarbon expulsion area is the transition area of the Dongpu Depression associated with the thickest source rocks. Es3M and Es3L source rocks in the transition area with high organic matter abundant and type II kerogen are more promising than the other formations. This study is the first to report on effective source rocks in different sedimentary environments in lacustrine basins and can provide guidance for future exploration in the Dongpu Depression and a reference for future research on source rocks in other lacustrine basins.

Paleoenvironment and organic matter enrichment of the Carboniferous volcanic-related source rocks in the Malang Sag, Santanghu Basin, NW China

Volcanic activity was quite frequent during the deposition of the Late Carboniferous Ha’erjiawu Formation in the Santanghu Basin. The petrology and organic and inorganic geochemical indicators were used to investigate hydrocarbon potential, paleoenvironmental conditions and organic matter enrichment of the mudstones. The results show that the oil generation capacity of the Ha’erjiawu Formation mudstones, which has abundant oil-prone organic matter (Type II kerogen with hydrogen index values mainly ranging from 250 to 550 mg HC/g TOC) in mature stage (Tmax values mainly ranging from 435 to 450 °C), is considerable. The Ha’erjiawu Formation was deposited in a dysoxic, freshwater-mildly brackish, and warm-humid environment. During its deposition, the Ha’erjiawu Formation received hydrothermal inputs. The volcanic hydrothermal activities played an important role in the organic matter enrichment. In addition, the total organic carbon (TOC) is significantly positively correlated with the felsic mineral content, but it is negatively correlated with the carbonate mineral content and C27/C29 ratios, indicating that terrigenous organic matter input also contributed to the primary productivity in the surface water. Therefore, the formation of the high-quality source rocks in the Ha’erjiawu Formation was jointly affected by the hydrothermal activity and the terrigenous organic matter input.

Source Rock Characterization of Silurian Tanezzuft and Devonian Awaynat Wanin Formations the Northern Edge of the Murzuq Basin, South West Libya

Drill cutting samples (n = 92) from the Devonian Awaynat Wanin Formation and Silurian Tanezzuft Formation, sampled from three wells F1, G1 and H1, locate in the northern edge of the Murzuq basin (approximately 700 kilometers south of Tripoli). The studied samples were analyzed in the objective of their organic geochemical assessment such as the type of organic matter, depositional conditions and thermal maturity level. A bulk geochemical parameters and precise biomarkers were estimated, using chromatography-mass spectrometry (GC-MS) to reveal a diversity of their geochemical characterizations. The rock formations are having varied organic matter contents, ranged from fair to excellent. The total organic carbon (TOC) reached about 9.1 wt%, ranging from 0.6 to 2.93 wt% (Awaynat Wanin), 0.5 to 2.54 wt% (Tanezzuft) and 0.52 to 9.1 wt% (Hot Shale). The cutting samples are ranged oil-prone organic matter (OM) of hydrogen index (HI) ranged between 98 –396 mg HC/g TOC, related kerogen types are type II and II/III, with oxygen index (OI): 6 - 190 with one sample have value of 366 mg CO2/g. Thermal maturity of these source rocks is different, ranging from immature to mature and oil window in the most of Tanezzuft Formation and Hot Shale samples, as reflected from the production index data (PI: 0.08 - 034). Tmax and vitrinite reflectance Ro% data (Tmax: 435 – 454 & Ro%: 0.46 - 1.38) for the Awaynat Wanin. Biomarker ratios of specific hydrocarbons extracted from represented samples (n = 9), were moreover used to study thermal maturity level and depositional environments. Pristine/Phytane (Pr/Ph) ratios of 1.65 - 2.23 indicated anoxic to suboxic conditions of depositional marine shale and lacustrine source rock.

Petroleum geochemical properties of the oil shales from the Early Cretaceous Garau Formation, Qalikuh locality, Zagros Mountains, Iran

A suite of petroleum geochemical techniques including Rock-Eval VI pyrolysis, carbon analyzer, kerogen petrography and palynofacies, vitrinite reflectance (VRr), elemental analysis of kerogen (CHONSFe), gas chromatography (GC), gas chromatography–mass spectrometry (GC–MS), pyrolysis ((PY)-GC) and carbon isotope (δ13C) analyses were performed on 123 outcrop samples from 10 locations to characterize the properties of organic matter and the petroleum potential of the oil shales from the Early Cretaceous Garau Formation at Qalikuh locality in the High Zagros (Iran). To characterize the mineralogy and chemistry of the oil shales X-ray diffraction (XRD) and X-ray fluorescence (XRF) were performed.Together with our previous work (Rasouli et al., 2015), this is the first study in which organic geochemical and petrographical investigations on the Qalikuh oil shales were performed. Total organic carbon (TOC) content of the oil shales varies from 3.83 to 26.4 wt%, with a mean value of 16.5 wt%, suggesting excellent TOC content. The mean value of hydrogen index (HI = 557 mg HC/g TOC) and petroleum potential (S2 = 89 mg HC/g rock) for the oil shales is high, indicating the presence of highly oil-prone organic matter. Elemental analysis of kerogen shows the oil shales are predominantly enriched in Type II-S kerogen. The results of kerogen microscopy observations reveal that homogenous bitumen (as widespread cement by impregnation) and amorphous organic matter are the main organic components. The oil shales of the Garau Formation are mainly consisting of calcite minerals and therefore they are classified as organic-rich/highly bituminous limestone. Additional data from molecular geochemistry and biomarker parameters of GC and GC–MS (e.g. CPI, Pr/Ph, Pr/nC17, Ph/nC18, DBT/Phen and C29/C27 20R sterane) as well as carbon isotope data of extracted bitumen confirm the presence of marine Type II kerogen. These data also show the oil shales were deposited within a marine carbonate environment under anoxic/euxinic conditions.Based on equivalent VRr, elemental analysis, microscopy evidence and biomarker maturity parameters the investigated oil shales from the Garau Formation are early mature and located in the oil generation window. The revised oil-yield calculation from Fischer Assay results confirms the occurrence of moderate to good commercial oil shales with oil yield of 83 l/ton rock on average. Moreover, preliminary analyses of PY-GC data indicate that the Qalikuh oil shales have also very good shale gas potential at over-mature state (i.e. VRr >1.3%).

Paleoenvironmental conditions, organic matter accumulation, and unconventional hydrocarbon potential for the Permian Lucaogou Formation organic-rich rocks in Santanghu Basin, NW China

Organic-rich rocks have received increasing attention for they are essential for evaluating hydrocarbon potential and unravelling the interaction between Earth surface environments and the biosphere. In this paper, we performed a combination of mineralogical, inorganic and organic geochemical analyses on a 200-m core of the Permian Lucaogou Formation organic-rich rocks obtained from Santanghu Basin, NW China, to investigate paleoenvironmental conditions, organic matter accumulation, and hydrocarbon potential. The redox- and salinity-sensitive proxies (e.g. V/Cr, V/(V+Ni) and Sr/Ba, Rb/K, B/Ga, and B content), together with the wide distribution of pyrite and carbonate minerals in these dark, thinly laminated organic-rich rocks, suggest that dysoxic-anoxic, brackish-saline, alkaline conditions prevailed during the deposition of the Lucaogou Formation in the Santanghu Basin. The occurrence of hydrothermal minerals, including strontianite and barite, and enrichments of B (up to 158.0ppm), Mn (up to 1291ppm), and certain incompatible elements (Li (up to 923ppm), Rb (up to 848ppm), Sr (up to 1760ppm), Hf (up to 12.7ppm)) as well as Ni vs. Co vs. Zn and Fe vs. Mn vs. (Cu+Co+Ni)×10 ternary diagrams demonstrate that the Lucaogou Formation received hydrothermal input during deposition, which suggests hydrothermalism was the source of brine that has caused the salinization of the water column.The positive correlation of HI value and TOC content, together with redox-sensitive proxies, illustrates primary productivity in surface water and preservation in anoxic bottom water collectively contributed to the enrichment of organic matter. Moreover, the positive correlation between silicate mineral content and TOC content and the negative correlation between carbonate content and TOC content suggest that terrigenous input as the main source of nutrients promoted organic matter accumulation, while carbonate constituents acted as a diluent to organic matter accumulation during deposition of the Lucaogou Formation. The faint positive correlation between TOC content and hydrothermal intensity indicator (Cr/Zr) seems to indicate that hydrothermal fluids may provide an additional source of nutrients for organic matter accumulation.In addition, the oil generation capacity of Lucaogou Formation, with abundant oil-prone organic matter (Type I/II1 kerogen with HI values ranging from 421.18–918.41mgHC/g TOC) in the early mature to mature stage (Tmax values ranging from 435 to 451°C), is considerable. The Rock-Eval oil saturation index (OSIS1/TOC×100) values range from 6.04–164.07mgHC/g TOC, suggesting the Lucaogou Formation contains producible oil. The high brittle mineral (including quartz and carbonates) contents (>50%wt%) and traces of clay minerals (<5wt%) imply that the Lucaogou Formation is likely to respond well to hydraulic stimulation. Consequently, the Lucaogou Formation in Santanghu Basin is expected to be a potential lacustrine shale oil play.

Organic geochemistry and oil-generating potential of the Oligocene–Early Miocene Dingqinghu Formation sediments in the Lunpola Basin, Tibet

The hydrocarbon source rock potential of shales from the Oligocene–Early Miocene Dingqinghu Formation was evaluated using organic geochemistry (Rock-Eval pyrolysis, total organic carbon (TOC) and bitumen extraction) and organic petrology. Forty-one outcrop samples from Lunbori and Jiangria Co shales in the Lunpola Basin were analysed. At Lunbori, in the central part of the basin, the shales have very good source rock potential, and show TOC contents ranging from 3.72 to 11.2 wt%, with an average TOC value of 7.36 wt%, S 2 values of 33.4 – 99.5 mg HC/g rock (average 61.8 mg HC/g rock), and extractable organic matter contents varying from 513 to 4525 ppm (average 2105 ppm). The shales have very good source rock potential. Rock-Eval T max values of 433 – 437°C (average 435°C) and high carbon preference index (CPI) values (4.76 – 6.70) indicate that the organic matter is immature to early mature for oil generation. The yellow fluorescence of kerogen under UV light is in good agreement with T max and CPI data. High hydrogen indices (HI) (635 – 1057 mg HC/g TOC) and H/C ratios (1.60 – 1.72) indicate that the Lunbori shales contain oil-prone organic matter and are characterized by high yellow fluorescing amorphous sapropelite content. The Lunbori shales contain a high content of hydrogen-rich Type II and minor Type I oil-prone kerogen, and have dominant medium to long molecular weight n -alkanes (maximizing at C 25 or C 27 ) with marked odd carbon number preference in the n -C 23 – n -C 31 range, pristine/phytane (Pr/Ph) ratios of 0.06 – 0.14, high phytane/ n -C 18 ratios (10.95 – 30.63), abundant gammacerane (gammacerane/C 31 hopane: 0.44 – 1.80), and predominant regular sterane C 27 . These data indicate deposition in stratified, anoxic and saline depositional conditions with a kerogen predominatly formed from a lacustrine biota. The Jiangria Co shales in the western part of the Lunpola Basin contain some hydrogen-rich Type I and II oil-prone kerogens at a marginally mature level. They have TOC contents of up to 2.62 wt%, S 2 values of up to 17.2 mg HC/g rock and extractable organic matter contents of up to 1731 ppm, indicating good source rock potential for oil generation. This is supported by their high HI values (420 – 720 mg HC/g TOC) and H/C ratios (1.05 – 1.50). The biomarker distributions of the extracts are characterized by odd carbon number predominance (C 23 –C 31 ), low Pr/Ph ratios (0.05 – 0.09), high concentrations of phytane and high gammacerane content, indicating lacustrine reducing and saline conditions.

Pore characteristics differences between clay-rich and clay-poor shales of the Lower Cambrian Niutitang Formation in the Northern Guizhou area, and insights into shale gas storage mechanisms

To study organic matter and pore characteristics of the Lower Cambrian Niutitang organic-rich shales, 166 shale samples from the Niutitang Formation were collected from the studied well, drilled in Kaiyang county in the Northern Guizhou area, Upper Yangtze region. All of the 166 shale cores were analysed for total organic carbon (TOC), total sulfur (TS), and the stable carbon isotope of kerogen (δ13Corg). Shale samples with varying TOC values were chosen for mineral composition analysis, helium porosity measurement and low pressure nitrogen adsorption measurement. The Lower Cambrian Niutitang Formation features high organic matter content, type I oil-prone organic matter, ultra-thick organic-rich shales, and an abundance of brittle minerals exhibiting favourable characteristics for the Lower Cambrian shale gas exploration in the Upper Yangtze region. Helium porosity measurement and low pressure nitrogen adsorption measurements were performed on selected shale samples with varying TOC content in order to analyse and characterize pore characteristics. Significant differences in mineral composition and pore characteristics were found between clay-rich and clay-poor Niutitang shales. Quartz weakly correlated with TOC content in clay-rich shales, which contained minor biogenically contributed quartz and performed better in terms of reservoir properties than clay-poor shales, and exhibited higher porosity, maximum nitrogen quantity adsorbed, pore volume, and specific surface area. In clay-rich shales, the maximum nitrogen quantity adsorbed, total pore volume, and specific surface area positively correlated with TOC content (R2=0.77, 0.79, and 0.75, respectively). The pore volume of clay-rich shales was dominated by mesopores, and both micropore and mesopore volume of clay-rich shales correlated significantly with TOC content. In clay-poor shales, quartz positively correlated with TOC content, indicating biogenic contribution to quartz. Micropore volume and mesopore volume of clay-poor shales were weakly positively correlated with TOC content. Pore volume, especially mesopore volume, may be affected by the recrystallization of biogenic silica, exhibiting identical micropore volume with clay-rich shales but lower mesopore volume.

Estimation of Enriched Shale Oil Resource Potential in E2s4L of Damintun Sag in Bohai Bay Basin, China

Qualitative and quantitative evaluations of resource potential are of significant importance for both exploration and exploitation of shale oil. We investigate the shale oil resource potential in E2s4L (the lower submember of the fourth member of the Paleogene Shahejie Formation) of Damintun Sag by both qualitative and quantitative methods. From the viewpoint of qualitative evaluation, it is reasonable to hope that the target shale, with adequate oil-prone organic matter (OM) in the peak and late oil generation stage, forms a shale oil reservoir. The total oil content in shale is evaluated from free hydrocarbons in shale (S1) by correcting the heavy and light hydrocarbons and the resins and asphaltenes. The total oil content is found to be over 4.45 times greater than the original S1. The evaluation threshold of high-abundance oil is determined by both the total oil content (ST) and the ratio of ST to the total organic carbon content with values that are greater than 8 mg/g and 1, respectively. Based on t...

An overview on source rocks and the petroleum system of the central Upper Rhine Graben

The petroleum system of the Upper Rhine Graben (URG) comprises multiple reservoir rocks and four major oil families, which are represented by four distinct source rock intervals. Based on geochemical analyses of new oil samples and as a review of chemical parameter of former oil fields, numerous new oil–source rock correlations were obtained. The asymmetric graben resulted in complex migration pathways with several mixed oils as well as migration from source rocks into significantly older stratigraphic units. Oldest oils originated from Liassic black shales with the Posidonia Shale as main source rock (oil family C). Bituminous shales of the Arietenkalk-Fm. (Lias α) show also significant source rock potential representing the second major source rock interval of the Liassic sequence. Within the Tertiary sequence several source rock intervals occur. Early Tertiary coaly shales generated high wax oils that accumulated in several Tertiary as well as Mesozoic reservoirs (oil family B). The Rupelian Fish Shale acted as important source rock, especially in the northern URG (oil family D). Furthermore, early mature oils from the evaporitic-salinar Corbicula- and Lower Hydrobienschichten occur especially in the area of the Heidelberg-Mannheim-Graben (oil family A). An overview on potential source rocks in the URG is presented including the first detailed geochemical source rock characterization of Middle Eocene sediments (equivalents to the Bouxwiller-Fm.). At the base of this formation a partly very prominent sapropelic coal layer or coaly shale occurs. TOC values of 20–32 % (cuttings) and Hydrogen Index (HI) values up to 640–760 mg HC/g TOC indicate an extraordinary high source rock potential, but a highly variable lateral distribution in terms of thickness and source rock facies is also supposed. First bulk kinetic data of the sapropelic Middle Eocene coal and a coaly layer of the ‘Lymnaenmergel’ are presented and indicate oil-prone organic matter characterized by low activation energies. These sediments are considered as most important source rocks of numerous high wax oils (oil family B) in addition to the coaly source rocks from the (Lower) Pechelbronn-Schichten (Late Eocene). Migration pathways are significantly influenced by the early graben evolution. A major erosion period occurred during the latest Cretaceous. The uplift center was located in the northern URG area, resulting in SSE dipping Mesozoic strata in the central URG. During Middle Eocene times a second uplift center in the Eifel area resulted in SW-NE-directed shore lines in the central URG and contemporaneous south-southeastern depocenters during marine transgression from the south. This structural setting resulted in a major NNW-NW-directed and topography-driven migration pattern for expelled Liassic oil in the fractured Mesozoic subcrop below sealing Dogger α clays and basal Tertiary marls.

Organic petrographic characteristics of the Crocker Formation, NW Sabah, Malaysia

The deep marine Crocker Formation in NW Sabah, Malaysia has been well studied in terms of sedimentology, stratigraphy and structural geology. However, not much is known about its potential as a petroleum source rock. This study partly addresses this subject by means of petrographic analysis to characterise the Crocker sediments in terms of its organic matter content and thermal maturity. Crushed rock samples mounted in resin blocks were examined under reflected white and ultraviolet light. Petrographic analysis indicates that the Crocker Formation samples have low phytoclast content (<2%). The mostly indigenous phytoclasts (microscopic plant fragments) can be divided into 4 groups based on their reflectance values; vitrinite with dark inclusions (lowest reflectance), vitrinite, oxidised vitrinite and inertinite (highest reflectance). These phytoclast groups exhibit a reflectance profile of 0.6, 0.8, 1.0 and 1.2%Ro respectively. Such an approach (measuring the reflectance of different phytoclast groups) can aid the petrographer to evaluate and validate vitrinite reflectance measurements in samples such as the Crocker that has a variable phytoclast assemblage. The average vitrinite reflectance is 0.82%Ro, which indicates that the Crocker sediments analysed were once buried to a depth of 4.1 km on average. Although its thermal maturity is within the oil generation window at present day, the Crocker Formation is considered a poor petroleum source rock because it is poor in phytoclast content (<2%) and appears to lack oil-prone liptinitic macerals. However, favourable source rock units could exist within the Crocker in the form of slump or mass- transport units, if the organic or phytoclast content is high enough and oil-prone organic matter is sufficiently present. Further geochemical analysis and regional data need to be incorporated for a more comprehensive analysis and assessment of the Crocker as a petroleum source rock and/or an analogue for subsurface geological units.

Hydrocarbon potential of the Sargelu Formation, North Iraq

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI = 3− to 3+, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R28 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.

Organic Geochemical Evaluation of Cretaceous Potential Source Rocks, East Sirte Basin, Libya

Cutting samples (n = 93) from the Sirte, Tagrifet, Rakb, Rachmat, Bahi Formations of Upper Cretaceous and Nubian Formation (Lower Cretaceous) derived from eleven wells (6C1-59, 6J1-59, 6R1-59, KK1-65, OO2-65, M1-51, KK1-65, B-96, B-95, B-99, E1-NC-59) locate in the Amal, Gialo, Nafoora, and Sarir Fields present in East Sirte Basin were analysed in the aim of their organic geochemical evaluation. A bulk geochemical parameters and evaluation of specific biomarkers by chromatography-mass spectrometry (GC-MS) implemented to find out a diversity of interbedded non-marine lithofacies including sandstones, siltstones, shales and conglomerates. Such rocks are good source and contain fair to good contented of organic matter passing in the course of very good, in which the excellent source rocks have organic carbon richness (TOC) reached to 5.16 wt%. The studied samples are ranged from gas to oil-prone organic matter (OM) of hydrogen index (HI) ranged between 115 - 702 mg HC/g TOC, related with gas prone (OM) of (HI) 300, associated with oxygen index (OI): 3 - 309 mg CO2/g TOC indicate that organic matter is dominated by Type II/III kerogen. The maturity of these source rocks is variations ranges from mature to post-mature-oil window in the Sirte and Rachmat Formations, as inferred from the production index (PI: 0.07 - 1.55) and Tmax and Ro% data (Tmax: 425 - 440/Ro%: 0.46 - 1.38) and early to mid-stage maturities for the other formations. Low PI in some samples seems to imply that the most of the hydrocarbons have expelled and migrated from the rocks. Biomarker ratios of individual hydrocarbons in rock extracts (n = 21), were also used in order to investigate the samples’ thermal maturity and palaeo depositional conditions. Pristine/Phytane ratios of 0.65 - 1.25 and dibenzothiophene to phenanthrene (DBT/P) ratios of 0.04 - 0.47 indicated Anoxic and suboxic conditions of depositional source rock. The origin of OM of the studied samples attributed to a marine algal source as indicated from the dominated by the C27 and co-dominant C28 homologues sterane in molecular composition distributions. The marine shale and carbonate lithofacies of rock samples were also indicated by high C19TT/C23TT ratio and low relative abundance of C24TeT/C23TT, consistent with their interpreted marine affinity. An organic geochemical evaluation pointed out that the Sirte Shale formation (Campanian/Turonian) is the main source rock in this petroleum area.