Equivalent Vitrinite Reflectance Research Articles

Unlocking the geochemical features of the Paleocene southern Pacific Ocean using carbon isotopes and biolipids

Little is known about the Paleocene in the southern Pacific Ocean due to scarce marine records. Here, we present a systematic geochemical investigation using biomarkers, carbonate content, and carbon isotopes of a set of early Paleocene deep-sea cores from International Ocean Discovery Program Expedition 378 Site U1553. The results provide a new Paleocene biomarker profile for the Campbell Plateau, New Zealand. The occurrence and distribution of a series of hopenes, ββ hopanes, sterenes and biomarker-based maturity parameters indicate that these organically-lean sediments are in an early diagenetic stage, with an equivalent vitrinite reflectance of approximately 0.4%. Biomarker data (e.g., gammacerane index and homohopane index), carbonate carbon isotopes (−27.9 ‰ to +2.0 ‰) combined with onboard data (sulphur and methane contents) indicate that the redox properties of the Paleocene southern Pacific Ocean changed from an oxidising-anoxic transition zone to a more reducing marine environment (water depth > 1000 m). The sources of the organic matter are diverse, including algae, bacteria, diatoms, dinoflagellates, and higher plants, but are dominated by aquatic organisms. Our new biomarker record bridges a Paleocene biosphere knowledge gap in the high latitude South Pacific.

PALYNOFACIES STUDIES OF THE LATE CRETACEOUS (TURONIAN-MAASTRICHTIAN) STRATA FROM JAURO JATAU, GONGOLA SUB-BASIN, NORTHERN BENUE TROUGH, NIGERIA

Geographically located within Gombe, Bauchi, and Yobe states, the Gongola Sub-basin has drawn attention from several academics looking to increase Nigeria's oil reserves relative to the inland frontier basins. This paper's goal is to determine the thermal maturity of strata from drill samples of the Fika shales in Nigeria's Northern Benue Trough, Gongola Sub-basin. To predict the well section's maturity and kerogen type, this study uses optical and organic facies studies. Twenty-seven samples of ditch cuttings were prepared using the universally accepted acid palynological procedure. The dispersed mounted slides revealed a variety of pollen, spores, and palynomacerals upon microscopic inspection. The well section under study exhibits a range of thermal maturation from mature to late mature, indicating the possibility of producing oil and gas. This corresponds to a range of thermal alteration values of 4 – 6 and equivalent vitrinite reflectance (%Ro) values of 0.6% – 1.35%. The total recovered Sedimentary Organic Matter (SOM) in this study was classified into Palynomorphs, Amorphous Organic Matter (AOM) and Phytoclasts and plotted on a ternary graph. The Percentage frequencies of AOM, Phytoclast and Palynomorphs were compared with the zones of the Tyson Ternary diagram. Most of the distribution frequencies lie within zones II, IX, VI and Iva suggesting Kerogen types III (gas-prone) and II (oil-prone).

Shale gas play of the silurian hot shale, Ghadames Basin, North Africa: Insights from integrated geochemistry and basin modeling

The lower Silurian hot shale in the Ghadames Basin was investigated to provide a regional assessment of the future prospects of shale gas play as an important unconventional resource system in one of the top African superglobal petroliferous sedimentary basins. The unconventional natural gas potential of the hot shale was studied based on regional improved organofacies assessment, thermal maturity, the timing of generation and expulsion, and sweet gas spot analysis, such as gas in place (GIP), total expelled gas (TEG), and total retained gas (TRG). The integration between regional geology and organic geochemistry, together with the proper regional utilization of the multi-dimensional basin modeling to better appreciate the importance of the Silurian hot shale as a key future shale gas unconventional-rich petroleum system (URPS) in the Ghadames Basin. The relationship between the richness and thermal parameters, such as the total organic carbon indicator (%TOC), hydrogen index (HI), measured and time step (calibrated models) vitrinite and equivalent vitrinite (%VRo) reflectance were used to develop quality control models for the regional natural gas spots of the Silurian hot shale were present-day mapping presentations are utilized as well for each parameter to better appreciate the lateral variability of the dry gas volumes. Regional basin control parameters from several key wells, such as heat flow levels, formation pressure system, and basin porosity were successfully utilized for the hot shale gas play resource screening (sweet spots) study utilizing multi-dimensional modeling approaches. The established regional spatial type B marine organofacies of the hot shale with excellent geochemical properties (∼18 %TOC) and regionally sufficient thermal maturation (∼2.45 %VRo, post-mature stage) indicate a significant amount of natural gas expelled and retained that has occurred in the Silurian hot shale system. The estimated GIP of the hot shale is about 120 bcf/km2 (equivalent to 320 bcf/section). The maximum expelled gas (TEG) amount is defined with values up to 88 bcf/section and the total estimated volume of the retained gas (TRG) is up to 96 bcf/km2, with the current geological architecture, geochemical properties, volumes, and distribution of the hot shale dry gas sweet spot in the Ghadames Basin. The hot shale can be considered in the near future for extensive further studies and exploration and development plans in Libya, Algeria, or Tunisia.

Hydrocarbon generation potential of Campano-Maastrichtian to Paleogene shales in the Benin Flank of the Anambra Basin, SW Nigeria

The hydrocarbon generation potential of the Campano-Maastrichtian to Paleogene shales from the Benin Flank (located in SW Nigeria) of the Anambra Basin, has been previously investigated mostly by studying outcrops and by relatively few subsurface data-based studies. Thus, it is expedient undertaking an assessment of the hydrocarbon generation potential of this frontier area from subsurface samples. Campano-Maastrichtian to Paleogene shale samples obtained from Egoli-1 borehole in the Benin Flank of the Anambra Basin are studied by means of HAWK programmed pyrolysis, organic petrography, and mineralogy (XRD), with the aim to explore the petroleum-generating potential and the thermal maturity. The obtained results display a significant variation of the TOC content ranging from very low (<0.5%) to significant (>5%), indicating poor to excellent oil potential based on S2 values under the condition, of course, the studied formations reached the oil window. The shales of the Nsukka and Imo Formations display lower petroleum-generating potential than these of the Mamu Formation. All the studied samples are dominated by gas-prone (type III) and inert (type IV) kerogens, with few displaying mixed II/III (oil- and gas-prone). The organic-petrography observations support partly the results of the HAWK programmed pyrolysis, as they reveal an organic-richer Mamu Formation in comparison to the Nsukka and Imo Formations; huminite/vitrinite particles (both indigenous and recycled) along with variable contents of liptinite (mostly alginite and bituminite) and inertinite macerals (mostly inertodetrinite) are hosted in the shales. The latter display a typical composition for fine-grained clastic sediments; mostly kaolinite, illite/montmorillonite, quartz, and subordinately, anatase. In terms of thermal maturity, huminite/vitrinite reflectance data points to immature stage; however, the occurrence of solid bitumens, displaying equivalent vitrinite reflectance values within the oil window, points to an active petroleum system in sequences deeper than the examined ones.

Organic petrology and geochemistry of the Devonian-Mississippian bakken formation, Williston Basin, North Dakota

The Devonian–Mississippian (D–M) black shales of the Bakken Formation are of interest as a hydrocarbon source due to their high total organic carbon (TOC; 2.2–17.4%) content. The Upper and Lower Members of the Bakken Fm. are shallow marine (100–150 m) sequences. Thirty samples were selected for maceral identification, kerogen typing, and solid bitumen reflectance (SBRo) based on TOC content and down-core spacing. The shales contain alginite, bituminite, abundant solid bitumen (SB), and minor amounts of inertinite. Solid bitumen increases in quantity with increasing thermal maturity. Pyrolysis (85 samples) provided S1 (avg. 8.0 mg HC/g rock), S2 (avg. 24.3 mg HC/g rock), hydrogen index (HI; avg. 201 mg HC/g TOC), oxygen index (OI; avg. 7 mg CO2/g TOC), and Ro (0.60–1.03%) calculated from Tmax. Plots of HI vs. OI and HI vs. Tmax (°C) were used to assess kerogen type but are not consistently in agreement with the petrographic assessment. Some samples from more thermally mature cores plot as Type III (vitrinite) kerogen instead of Type II (alginite and bituminite) kerogen, the latter confirmed through petrographic observations of lower maturation samples. This is largely due to increased SB in more thermally mature samples (Ro = 0.83–1.03%), as SB is known to have a lower HI content than Type II kerogen. Petrographic data show more alginite and bituminite (19–55%) in the thermally less mature samples (Ro = 0.60–0.83%) compared to more dispersed SB (67–86%) and less alginite and bituminite (<1%) in the more thermally mature samples (Ro = 0.89–1.01%).Early research on the Bakken Fm. reported lower than expected vitrinite reflectance values and attributed them to vitrinite “suppression”. The scarcity of vitrinite and abundance of SB suggest that early work likely reported reflectance on SB. Recent attempts to assess the thermal maturity of the Bakken black shales have converted SBRo to vitrinite reflectance equivalence (VRE). However, there are multiple SB populations present in these shales and it is not always clear which SB populations were included, possibly contributing to error. In the current study, only smooth, homogenous SB was measured (0.68–1.14% SBRo) and VRE values calculated (0.54–1.49%) to assess thermal maturity from the basin margin to the depocenter; inclusion of measurements on granular, heterogeneous SB (14–21 vol%), which are ~53% lower than those for smooth, homogenous SB (3–12 vol%), results in lower mean reflectances, especially in more mature samples. Vitrinite reflectance equivalent data calculated using the D–M New Albany Shale equation of Liu et al. (2019) agrees with liptinite fluorescence and Rock-Eval Ro, whereas VRE based on the D–M Woodford Shale equation of Cardott and Comer (2021) does not. This suggests the importance of applying VRE equations from similar formations both in terms of thermal history, as well as kerogen type and age. Results from SBRo, Rock-Eval Ro, VRE, and observations of alginite fluorescence indicate that samples from the current study range from the early oil window into the condensate, wet gas zone.

A Cryogenian interglacial source rock in South China: Geochemistry, spatial distribution and organic matter enrichment

The organic-rich Datangpo Formation was deposited between Sturtian and Marinoan glaciations during the Cryogenian in South China. As a set of source rocks with great petroleum exploration prospect, it is important to understand how the glacial ocean transformed into a favorable condition for organic matter (OM) accumulation for evaluating its hydrocarbon potential. Here, the organic and inorganic geochemical data were tested, and the lithological and geochemical data were compiled to study the spatial distribution and OM enrichment of Datangpo Formation. The Datangpo Formation is a set of good quality (average total organic carbon (TOC) content = 1.83 %), sapropelic OM type (light organic carbon isotopes (δ13Corg) and overmature source rocks (average solid bitumen Raman spectroscopy equivalent vitrinite reflectance (Requ) = 4.28%). The areas of thickest source rock are located in the Xiushan and Tongren, and spatial distribution was controlled by rift activity and the erosion by the Marinoan glaciation instead of the remnant glacial topography of the Sturtian glaciation. The OM enrichment of Datangpo Formation was controlled by anoxic/euxinic water condition, high sedimentary rate, and high productivity. The primary productivity in interval Ⅰ and Ⅱ was promoted by hydrothermal nutrients continued since late Sturtian glaciation and few terrigenous nutrients, and terrigenous nutrients of continental weathering during greenhouse period, respectively.

Biostratigraphy, organic petrography and carbon isotope chemostratigraphy of the Ordovician-Silurian black shales from the Northwestern Domain of Peninsular Malaysia

Integrated biostratigraphy, petrography, organic carbon and carbon isotope chemostratigraphy were used in tandem to assess the paleoenvironment and hydrocarbon potential of the latest Ordovician to Early Silurian basin in the Northwestern Domain of Peninsular Malaysia. Graptolite biostratigraphy indicated a Hirnantian to Aeronian age for the Tanjung Dendang Formation in Pulau Langgun, Langkawi. The graptolite fauna from the Langkawi Islands demonstrates a close association with the South Chinese fauna. The graptolite fragments show a non-granular surface morphology and are mostly present in a long, stipe-like, lath shape when observed under reflected white light microscopy. The pyrites present are relatively small and sparse during the latest Ordovician, suggesting a euxinic condition, but during the Silurian, the pyrites are larger and more common, suggesting anoxic and later dysoxic bottom water. The mean random reflectance of non-granular graptolite in sections perpendicular to the bedding range from 1.8% to 3.07%, and the equivalent vitrinite reflectance ranges from 1.86% Ro to 3.12% Ro, suggesting an overmature stage in term of hydrocarbon generation. The TOC of the Langkawi black shale averages 2.1 wt%, while the rock from the Mahang and Sungai Petani areas measures 1.37 wt% and 0.47% wt%, respectively. δ13Corg chemostratigraphy for the Tanjung Dendang Formation resulted in δ13Corg level between −31.4 ‰ to −28.7 ‰. The Hirnantian Isotope Carbon Excursion (HICE), signalled by a high δ13Corg value, is documented near the base of the formation, followed by a sudden negative shift towards the Ordovician-Silurian boundary. δ13Corg more or less maintained during the Silurian except for slight carbon excursion events during the middle Rhuddanian and early Aeronian. The δ13Corg excursion events from the Tanjung Dendang Formation in Langkawi can be accurately correlated with successions from China, the United Kingdom and Artic Canada.

Geochemical characteristics and exploration significance of ultra-deep Sinian oil and gas from Well Tashen 5, Tarim Basin, NW China

The Well Tashen 5 (TS5), drilled and completed at a vertical depth of 9017 m in the Tabei Uplift of the Tarim Basin, NW China, is the deepest well in Asia. It has been producing both oil and gas from the Sinian at a depth of 8780–8840 m, also the deepest in Asia in terms of oil discovery. In this paper, the geochemical characteristics of Sinian oil and gas from the well were investigated and compared with those of Cambrian oil and gas discovered in the same basin. The oil samples, with Pr/Ph ratio of 0.78 and a whole oil carbon isotopic value of −31.6‰, have geochemical characteristics similar to those of Ordovician oils from the No. 1 fault in the North Shuntuoguole area (also named Shunbei area) and the Middle Cambrian oil from wells Zhongshen 1 (ZS1) and Zhongshen 5 (ZS5) of Tazhong Uplift. The maturity of light hydrocarbons, diamondoids and aromatic fractions all suggest an approximate maturity of 1.5%–1.7% Ro for the samples. The (4-+3-) methyldiamantane concentration of the samples is 113.5 μg/g, indicating intense cracking with a cracking degree of about 80%, which is consistent with the high bottom hole temperature (179 °C). The Sinian gas samples are dry with a dryness coefficient of 0.97. The gas is a mixture of kerogen-cracking gas and oil-cracking gas and has Ro values ranging between 1.5% and 1.7%, and methane carbon isotopic values of −41.6‰. Based on the equivalent vitrinite reflectance (Reqv = 1.51%–1.61%) and the thermal evolution of source rocks from the Cambrian Yu'ertusi Formation of the same well, it is proposed that the Sinian oil and gas be mainly sourced from the Cambrian Yu'ertusi Formation during the Himalayan period but probably also be joined by hydrocarbon of higher maturity that migrated from other source rocks in deeper formations. The discovery of Sinian oil and gas from Well TS5 suggests that the ancient ultra-deep strata in the northern Tarim Basin have the potential for finding volatile oil or condensate reservoirs.

The organic petrology of vitrinite-like maceral in the Lower Paleozoic shales: Implications for the thermal maturity evaluation

Vitrinite-like maceral (VLM) is a type of autochthonous, synsedimentary, dispersed organic matter, which is ubiquitous in many Lower Paleozoic marine shales. The VLM reflectance has been used as an alternative tool to evaluate the thermal maturity of pre-Devonian marine sediments lacking a classical vitrinite, however, the existing knowledge about its optical properties and reflectance characteristics is still relatively limited. In this study, the optical properties of VLM were examined by means of organic-petrological methods applied to a series of naturally and artificially matured VLM-rich shales samples and their reflectance crossplots. The strong positive correlation between the true maximum reflectance (Rmax) and bireflectance of VLM indicates the increasing anisotropy of VLM with increasing thermal maturity. VLM shows a linear coalification path in the studied shales. It displays biaxial neutral features in the samples with Rmax ≤ 2%, but shows obvious optically biaxial negative characteristics in the samples with Rmax > 2%. The shape of VLM reflectance indicating surface (VLMRIS) gradually becomes oblate with increasing maturity. These results indicate that VLM exhibits appearance and optical properties similar to vitrinite, and its reflectance can be used as a reliable indicator for thermal maturity evaluation. The equivalent vitrinite reflectance (EqVRo) values, which were calculated based on the mean measured maximum reflectance of VLM (VLMR¯max), evidence that the Niutitang Formation shales from China and Alum shales from Denmark are post-over mature, and the Yurtus Formation shales in Tarim Basin and the Alum shales from Sweden are still within the oil window.

The organic geochemistry of Permian high latitude sediments in two boreholes in the southern Sydney Basin, New South Wales, Australia

Twenty six samples of Permian high latitude sedimentary rocks from the southern Sydney Basin were analysed using organic geochemical methods for their thermal maturity, organic matter inputs, and depositional environment. Fourteen samples are from the Elecom Clyde River (ECR) DDH01 borehole (inland; Southern Highlands), and 12 are from the ECR-DDH07 borehole (coastal; near Nowra). The analysed formations are the Berry Siltstone, the Nowra Sandstone, the Wandrawandian Siltstone, the Snapper Point Formation and the Pebbley Beach Formation. This study is the first organic geochemical study of samples from the Berry Siltstone and Nowra Sandstone. The formations mostly have total organic carbon varying from 1 to 2 wt%, but the Snapper Point Formation is leaner in TOC (0.2–0.7 wt%). The samples vary from low to very high thermal maturity. The samples from the ECR-DDH01 borehole are in the early to middle of the oil window (vitrinite reflectance equivalent = 0.60–0.80%), based on hopane, sterane, alkylnaphthalene, alkylphenanthrene, alkylbiphenyl, and alkyldibenzothiophene thermal maturity parameters. The samples from the ECR-DDH07 borehole are much more thermally mature, in the late part of the oil window to the early gas window (vitrinite reflectance equivalent = 1.2–1.7%). This high thermal maturity has led to the loss of nearly all polycyclic biomarkers, and the thermal rearrangement of many groups of compounds, including monomethylalkanes. The ECR-DDH01 borehole location and time-equivalent outcrop samples south-west of Ulladulla have similar thermal maturities and are close to the margins of the Sydney Basin, and it is estimated to have previously been covered by about 3 km of overburden. In contrast, the samples in the ECR-DDH07 borehole were buried much deeper, with about 4–5 km of overburden, which means that only limited information about their source inputs and depositional environment could be recovered. Aliphatic biomarker, n-alkane and aromatic data are consistent with an overall strong terrigenous organic matter input for the samples from the ECR-DDH01 borehole. Sterane/hopane ratios are mostly low, but only a few compounds diagnostic of specific source inputs were identified. There is a microbially-dominated sample near the base of the Snapper Point Formation (high C29 αβ hopane/C30 αβ hopane ratio and 2α-methylhopanes), and high amounts of parent polycyclic aromatic hydrocarbons in some samples from the Berry Siltstone, likely reflecting an occasional pyrogenic signature from palaeo-forest fires. Several parameters, including sterane carbon number distributions, terpane ratios and the relative abundance of dibenzofuran compared to phenanthrene show that the samples from the ECR-DDH01 borehole have a more strongly terrigenous signal than the previously analysed outcrop samples. This is inferred to be because the ECR-DDH01 location was closer to the palaeo-shoreline than the likely more distal outcrop samples. Based on the pristane/phytane ratio and hopane distributions, deposition of the sediments was under varying oxicity conditions, from highly oxic to suboxic. The inferred environments are marine shale/lacustrine and fluvial/deltaic, so the organic geochemical data agrees with the Permian depositional history of the southmost part of the Sydney Basin previously inferred from sedimentological and palaeogeographic studies.

Origin of the Ultra-Deep Hydrocarbons from the Shunbei No. 1 Fracture Zone in the North of Shuntuoguole Low Uplift, Tarim Basin, North-Western China

In order to have a deeper insight into the accumulation mechanism of ultra-deep hydrocarbons, in this paper, the recently discovered ultra-deep Ordovician light oil and gas deposits (&gt;7200 m) in the Shunbei No. 1 fracture zone are studied intensively, including maturity, source kitchens, the extent of secondary alterations, and possible migration directions, based on an analysis of the molecular compositions and stable carbon isotopes of crude oils and natural gases. The average equivalent vitrinite reflectance (Rc) of these oils, estimated from light hydrocarbons (H versus I), MDI, DNR, and MDR, are about 1.50%, 1.58%, 1.48%, and 1.51%, respectively, which suggests that most of the oils are in the late stages of crossing the oil window. The two maturity grades (1.06–1.25% and 1.36–1.67%) of the oil samples calculated from the aromatic compounds indicate the presence of at least two stages of hydrocarbon charge. In addition, the positive correlation plot of DNR and MDR (y = 3.59x − 12.84; R2 = 0.96) indicates that oils in the southwestern region of the F1 (S1-11–S1-16) are slightly more mature than oils in the northeastern region of the F1 and the well at SL1, far from the No. 1 main fault zone. In addition, the study shows that these hydrocarbons belong to the same source kitchen of a reduced marine sedimentary environment with mixed organic matter comprising benthic and planktonic algae, based on biomarker parameters, light hydrocarbons, and carbon isotope compositions. The oil–oil correlation analyses suggest that the studied oil samples are probably derived from the in situ Lower Cambrian Yuertusi formation source rocks. Various geochemical parameters consistently show limited significant hydrocarbon alteration processes, indicating favorable preservation conditions in the study area. The integrated geochemical characteristics of the hydrocarbons allow us to infer that they mainly migrate vertically from the in situ Lower Cambrian Yuertusi formation source rocks toward the Ordovician reservoirs, followed by a certain degree of lateral migration from southwest to northeast.

Discovery of solid bitumen in the Cambrian reservoirs and its geological implications in the Ordos Basin, China

This study reports a comprehensive geochemical analysis of several samples of the solid bitumen recently discovered in the Cambrian reservoirs in drillings and outcrops in the Ordos Basin. The results show that the solid bitumen in the reservoir features intergranular pores and micro-fractures, with mineral particle surfaces of dolomite and limestone, and relatively clear and flat boundaries. The D and G peaks in the laser Raman spectrum were prominent. According to distributions of shapes of the D and G peaks and the relevant parameters of the laser Raman spectrum, the vitrinite equivalent reflectance (Roeq) values were from 2.12% to 3.46% in the solid bitumen. This indicates that the solid bitumen in the reservoirs had undergone significant thermal evolution and was mainly composed of pyrobitumen. Moreover, it mainly consisted of four types of atoms, C, O, Ca, and Mg, which confirms the hypothesis of the significant thermal evolution of the samples. In addition, the analysis of the origin of the Cambrian natural gas and the correlation between the solid bitumen and the potential source rocks show that the solid bitumen in the Cambrian reservoirs of the Southern Basin had features similar to those of the Lower Cambrian source rocks, except for the samples from well T59. All evidence suggests that the high-abundance source rocks of the Lower Cambrian have made considerable contributions to the Cambrian natural gas and the solid bitumen in the Cambrian reservoirs of the Southern Basin. The work here provides a new scientific basis for exploring natural gas in the Cambrian reservoirs and deep strata of the Ordos Basin.

Thermal maturity calibration of extremely high-mature pre-Devonian strata: A case study from the Lower Cambrian Qiongzhusi Formation in the Sichuan Basin, South China

Thermal maturity assessment of pre-Devonian strata is challenging due to the absence of humic vitrinite, and conventional organic geochemical methods (i.e., Rock-Eval Tmax, atomic H/C, biomarker parameters) are usually ineffective for the highly-over mature source rocks. The Lower Cambrian Qiongzhusi Formation shale in the Sichuan Basin, as the main high-quality source rock, is an important exploration target for shale gas. In this study, optical reflectance and Raman spectroscopy measurements were performed on eight Qiongzhusi Formation core samples from well JY1 in conjunction with basin modelling to calibrate to equivalent vitrinite reflectance and constrain thermal maturity. The results reveal solid bitumens/pyrobitumens as the predominant organic constituents in the Qiongzhusi Formation. As burial depth increases from 3,300m to 3,600m, the solid bitumen reflectance acquired from optical measurement and Raman calculation increase from 2.53% to 3.86%, and from 2.88% to 3.49%, respectively, along with increasing optical anisotropy. The Raman-calculated solid bitumen reflectance data are consistent with the optical reflectance data at depths <3,500m, while the former become lower than the latter at depths >3,500m and are consistent with reflectance values constrained by basin modelling. We propose that the surface quality and granularity of solid bitumen, hydrothermal fluid alteration, and varied thermal conductivity of mineral matrix result in the higher optical reflectance of solid bitumen occurrence in the Qiongzhusi carbonates. The multidisciplinary calibration approach integrating optical reflectance measurement, Raman spectroscopy and basin thermal modelling is considered effective and more accurate for thermal maturity assessment.

Biomarkers, light hydrocarbons, and diamondoids of petroleum in deep reservoirs of the southeast Tabei Uplift, Tarim Basin: Implication for its origin, alteration, and charging direction

The Atan Bulge in the southwestern Tabei Uplift of the Tarim Basin provides insights into the geochemistry of the oils and condensates in deep Ordovician reservoirs because its reservoir burial depth is generally greater than 6000 m. To investigate the oil origin, alteration, and migration pathways, the carbon isotopes, biomarkers, light hydrocarbons, and diamondoids of 16 oil and condensate samples from the Ordovician reservoirs in the Atan Bulge were analyzed. The results show that chain alkanes dominate the light hydrocarbons, followed by cycloalkanes and aromatic hydrocarbons. 1-methyladamantane (MA) dominates the diamondoids, followed by 1,3-dimethyldiamantane (DMD). The samples lacked biodegradation and thermochemical sulfate reduction signatures. Except for a few samples near the Manjiaer Depression, the evaporative fractionation caused by late natural gas charging is generally weak. The oil geochemistry suggests that the oils and condensates are primarily derived from lower Cambrian marine shale, and the organic matter is mainly type II. The equivalent vitrinite reflectance (Rc) calculated using thermal maturity indicators derived from methylphenanthrene, methyldiamantanes, and C5–C7 light hydrocarbons, respectively, is in the ranges of 0.78%–1.04%, 1.1%–1.5%, and 1.06%–1.48%. The samples' low (3-+4-)-methyldiamantane concentrations (36–76 μg/g) imply a low level of oil cracking. The carbon isotope distribution among oil fractions and different maturity ranges suggest that crude oil was generated and charged multiple times. The maturity of the samples decreases from SSE to NNE, indicating that the petroleum likely migrated from strike-slip faults during its primary charging period, with the Manjiaer Depression and its slope serving as the primary source kitchens.

Comparison of the Ediacaran and Cambrian petroleum systems in the Tianjingshan and the Micangshan uplifts, northern Sichuan Basin, China

Several different types of petroleum occurrences (including solid bitumens, oil sands, and oil seeps) are observed in various strata (e.g., the Ediacaran, Cambrian, Devonian, Permian, Triassic, and Jurassic strata) of the Tianjingshan and the Micangshan uplifts, northern Sichuan Basin, China. However, the sources of these petroleum occurrences are still in dispute, because of the severe biodegradation, strong thermal alteration, and multiple tectonic movements. At present, such uncertainty in the potential source rock systems has hindered oil and gas exploration in the study areas. In this study, methods including catalytic hydropyrolysis and trace elements analysis were introduced into the oil-source correlation study, to avoid the influence of biodegradation and/or thermal alteration. The results show that the petroleum shows that occur in the Cambrian-Jurassic strata of the Tianjingshan area are characterized by low maturity (equivalent vitrinite reflectance (EqVRo) < 1.0%), light organic carbon isotopic ratios (δ13Corg values ranging from −34.0‰ to −38.4‰), a predominance of C29-steranes, enrichment in V and Mo, and strong depletion in Bi elements. In contrast, the solid bitumens in the Ediacaran Dengying Formation in the Micangshan area have high maturity (EqVRo > 2.0%), slightly heavier δ13Corg values ranging from −27.5‰ to −36.0‰, a predominance of C27-steranes, weak enrichment in Mo and strong depletion in Rb and Bi elements. In addition, the Ediacaran and the Lower Cambrian source rocks can be discriminated by the bound sterane distributions, trace element concentrations, and bulk δ13Corg values. Further oil-source correlation indicates that the petroleum shows in the Cambrian-Jurassic strata in the Tianjingshan area were dominantly derived from the Lower Cambrian Qiongzhusi Formation, while those in the Ediacaran Dengying Formation in the Micangshan area were mainly sourced from the Ediacaran Doushantuo Formation. Finally, the results of oil-source correlation, combined with the tectonic evolution history of the investigated areas further elucidate the occurrence and distribution of petroleum, which can assist in oil and gas exploration in the investigated uplifts and the adjacent areas.

Characteristics and Differences Analysis for Thermal Evolution of Wufeng–Longmaxi Shale, Southern Sichuan Basin, SW China

The marine shale of the Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation is the main source rock and the target of shale gas exploration in the southern Sichuan Basin. The maturity of organic matter (OM) is a vital indicator for source rock evaluation. Due to the lack of vitrinite, the organic matter maturity of the Wufeng–Longmaxi Formations in the southern Sichuan Basin is difficult to accurately evaluate. In total, 33 core samples of the Wufeng–Longmaxi Formations in the southern Sichuan Basin were selected to observe the optical characteristics of solid bitumen and graptolites and measure their random reflectance. Simultaneously, Raman spectroscopic parameters of kerogen were also used to quantitatively analyze the change in maturity. By using Raman spectroscopic parameters as mediators, conversion equations between graptolite random reflectance (GRor) and equivalent vitrinite reflectance (EqVRo) were established. Taking the calculation results of EqVRo as constraints, the tectono-thermal evolution history of Wufeng–Longmaxi Shale in the southern Sichuan Basin is constructed through basin modelling. The results show that the maturity of Wufeng–Longmaxi Shale in the western Changning, Luzhou-western Chongqing, eastern Changning and Weiyuan areas decreases successively. The EqVRo falls in the ranges of 3.61%~3.91%, 2.92%~3.57%, 3.08%~3.25%, 2.41%~3.12%, and the average EqVRo is 3.73%, 3.30%, 3.18% and 2.80%, respectively. Thermal evolution in western Changning was controlled by the thermal effect of the Emeishan mantle plume and paleo-burial depth, while the thermal evolution of other areas was mainly controlled by paleo-burial depth. This study provides a reliable parameter for the evaluation of thermal maturity and makes a more accurate calibration of the maturity of the Wufeng–Longmaxi Formations in the southern Sichuan Basin; it also expounds the factors for the differences in thermal evolution in different parts of the area.

Pyrolytic Evidence for Unsubstituted Aromatics as Potential Oil-Oil/Source Correlation Indicators.

Most oil source correlation indicators are invalid because of the high maturity of the deep marine strata. Thus, a suitable indicator with high thermal stability requires to be established. In this study, to understand the effect of thermal maturation on the carbon isotopic composition of unsubstituted aromatics, we performed a number of anhydrous thermal simulation experiments involving two typical Chinese shales (lacustrine and marine shales), their corresponding expelled oils, three crude oils, and their associated oil fractions, that is, saturates, aromatics, resins, and asphaltenes (SARA). The generated unsubstituted aromatics were examined in terms of molecular distributions and carbon isotopic composition. The results show that unsubstituted aromatics in different types of samples demonstrated similar variation characteristics. Phenanthrene can be formed continuously in 0.45%/0.55–2.30% Ro (equivalent vitrinite reflectance), especially in the high-over maturity stage. However, their carbon isotope composition shows minor variations. The unsubstituted aromatic carbon isotopic information in source rocks can be preserved during the whole pyrolysis process. Their carbon isotopic values in source rocks and their corresponding expelled oils are extremely similar. Furthermore, no evident difference exists in the carbon isotopes of unsubstituted aromatics formed by crude oil and associated oil fractions. These results indicate that these types of parameters are suitable for oil–oil/source correlation in deep marine strata with high-over maturity.

The maturity of Silurian Longmaxi shale in Jiaoshiba, Sichuan Basin: as revealed by laser Raman spectroscopy

Accurate estimates of the thermal maturity of organic matter are important in studies of shale oil and gas, as these data are directly related to the genesis type of shale gas, adsorption capacity of shale and formation of organic pores in organic-rich shale. Longmaxi shale is a major shale gas exploration target in South China and a typical overmature shale gas play. Because Longmaxi shale is Silurian marine strata without vitrinites, it is difficult to determine its maturity accurately. In order to evaluate the maturity of the Longmaxi shale exactly, in this paper, solid bitumen reflectance, basin modeling and laser Raman spectroscopy analyses of solid bitumen were carried out on the shale. The solid bitumen reflectance of Longmaxi shale is range of 2.77–4.14% with a mean of 3.5%, and the corresponding equivalent vitrinite reflectance (EqVRo) is 2.6%; additional information about the maturation is provided by the basin modeling with the constraint of the maximum paleo-geothermal about 210–220 °C which was indicated by thermo-acoustic emission measurement, fluid inclusion thermometry and equivalent vitrinite reflectance. In addition, the Raman was applied to Longmaxi shale in Jiaoshiba firstly, and the Raman inter-peak interval between peak G (graphitic band) and peak D (disordered band) is range of 270–279 cm−1, which suggests that equivalent vitrinite reflectance is about 2.67% and is consistent with the results of solid bitumen reflectance, infrared spectrum and basin simulation. Approximate conclusions have been drawn from these different methods, and the thermal evolution of Longmaxi shale in Jiaoshhiba area, the largest shale gas field in China, was estimated at approximately 2.5–2.7%, which means that it has reached the overmature dry gas stage. Overall, the findings also imply that Raman spectra of pyrobitumen can be used effectively to evaluate the maturation of the marine shale without vitrinites.

The thermal history in sedimentary basins: A case study of the central Tarim Basin, Western China

• Heat flow of the Shunbei area decreased since the Ordovician with a Permian peak. • The middle-lower Ordovician reservoirs experienced three stages of heating process. • Hydrocarbon charging periods of No.1, 5, and 7 strike-slip fault zones are different. The reconstruction of thermal history is essential for the superdeep (>6,000 m) hydrocarbon exploration and development in the Central Tarim Basin, Western China. This study first recovered the burial histories of five typical wells in the Shunbei area (the Central Tarim Basin) based on the drilling data and calculated the erosional thicknesses using the well-tie profiles. The thermal histories and hydrocarbon charging periods of the Shunbei area were studied with the measured equivalent vitrinite reflectance ( R equ ) and fluid inclusion assemblage homogenization temperature data, respectively. Except for some abnormal values, most R equ data with 0.45%–1.48% gradually increase with depth. The thermal modeling revealed that the heat flow in the Shunbei area gradually decreased since the Early Ordovician, with an abrupt peak of ∼45–47 mW/m 2 during the Early Permian. The temperature histories of the Ordovician Yijianfang and Yingshan Formation reservoirs in the Shunbei area could be divided into three stages of rapid heating (1.27–1.36 °C/Ma), slow heating (0.07–0.09 °C/Ma) and rapid heating (1.20–1.28 °C/Ma). We recognized three hydrocarbon charging periods in the No. 1 strike-slip fault zone, which occurred at ∼435–420 Ma, ∼263–220 Ma, and 18–3 Ma, respectively, while the No. 5 and 7 strike-slip fault zones only experienced the first two periods. This study provides new insights into the thermal history and hydrocarbon accumulation in the Shunbei area, which would be very useful for further superdeep oil and gas exploration and resource evaluation in the Central Tarim Basin.

Evolution of Ordovician YJ1X ultra-deep oil reservoir in the Yuecan oilfield, Tarim Basin, NW China

Based on a combined in-situ calcite U-Pb dating, molecular geochemical correlations of reservoir oil and extract from reservoir rocks, and fluid inclusion analysis, the charge and evolution history of the YJ1X ultra-deep oil reservoir of the Ordovician Yijianfang Formation in the southwestern part of the Tabei Uplift has been determined systematically. (1) The reservoir oil, free oil and inclusion oil have similar geochemical characteristics and are presumably derived from marine source rock deposited in similar sedimentary environment. (2) The reservoir oil, free oil and inclusion oil have similar maturities with calculated equivalent vitrinite reflectance values in the range of 0.80%–0.96%. (3) Two types (Group I and II) of oil inclusion assemblages (OIAs) have been identified in the reservoir, of which Group I represents the original gas-saturated oil entering the trap during the initial oil charge, whereas Group II represents undersaturated residual oil retained in the reservoir after minor leakage of light hydrocarbon. (4) The reservoir experienced oil charge only once during the Early Devonian around 425 Ma and has been well preserved after the minor light hydrocarbon leakage in the Middle Devonian. The study shows that there may be old oil and gas accumulations in ultra-deep strata of petroliferous basins with well-developed caprock and stable tectonic background.