Oil Generation Potential Research Articles

Conversion of the Oil and Gas Generation Potential of the Deep Source Formations of the West Siberian Basin: An Example of Well Tyumen SG-6

Conversion of the Oil and Gas Generation Potential of the Deep Source Formations of the West Siberian Basin: An Example of Well Tyumen SG-6

Synergistic Evolution of Palaeoenvironment—Bionts and Hydrocarbon Generation of Permian Saline Lacustrine Source Rocks in Jimusar Sag, Junggar Basin

This study focused on Middle Permian Lucaogou Formation saline lake source rocks, utilizing a combination of biomarkers and hydrocarbon generation thermal simulation to analyze their biological compositions, depositional environments, and hydrocarbon generation potential. The Pr/Ph ratio, Ph/nC18 ratio, and Pr/nC17 ratio indicate that the Lucaogou Formation was in a reducing environment during the deposition period, and the lower part of the Lucaogou Formation (P2l1) is more anoxic than the upper part of the Lucaogou Formation (P2l2). The maturity index 20S (%) and ββ (%) reflect that the maturity of organic matter in the P2l1 is slightly higher than that in the P2l2. The G/H index and the ETR index indicate that the stratification of the water column is better during the sedimentary period of Lucaogou Formation and the salinity of the P2l1 is higher than that of the P2l2. The biomarker parameters of nC21−/nC22+, CPI, S/H, and C22T/C21T reflect that the organic matter of the source rocks have a higher abundance of bacteria and algae than higher plants, and the contents of bacteria are more than that of algae. The (7- + 8-MMAs)/Cmax and (C28 + C29 − St)/St parameters indicate that cyanobacteria accounted for a certain proportion of bacteria, and the algae are mainly green algae. The co-evolution of the sedimentary environment and the biological composition reflects the control of the sedimentary paleoenvironment on biological composition. According to the relative content of cyanobacteria, green algae, and Rhodophyta, the source rocks of the upper and lower Lucaogou Formation correspond to the low-salinity type (LS-type) and the high-salinity type (HS-type), respectively. Compared with LS-type source rocks, HS-type source rocks have greater generation potential of oil and weaker gas generation potential. This study is valuable for the accurate assessment of source rocks and holds significant practical implications for the exploration of oil and gas resources.

Highly efficient catalytic pyrolysis of oil shale by CaCl2 in subcritical water

An innovative method combining CaCl2 with subcritical water is proposed for in-situ mining of oil shale. The catalytic hydrothermal pyrolysis of block Huadian oil shale was carried out at 350 °C to evaluate the feasibility and reaction mechanism of this method. After adding CaCl2, the time required for kerogen pyrolysis was shortened from 70 to 40 h, while the maximum expelled oil yield increased from 19.14% to 21.96%. This excellent catalytic activity indicated that CaCl2 was transported into shale matrix by subcritical water to catalyze the pyrolysis of kerogen. It was found that the C–O bonds in kerogen were first broken and then the whole decomposition of kerogen initiated. The compositional analysis of residual kerogen indicated that CaCl2 could facilitate the transportation of hydrogen from subcritical water to kerogen, thereby inhibiting the excessive condensation of kerogen to improve its oil-generating potential. The macromolecular compounds in expelled oil would undergo a secondary cracking reaction. Besides, CaCl2 could also promote the re-cracking and discharge of residual bitumen in oil shale matrix. These findings demonstrated that combining CaCl2 and subcritical water enabled efficient pyrolysis of block oil shale and provided a novel technique for in-situ mining of oil shale.

Geochemical investigation of oil seepages and Paleozoic sediments for determining probable source rock in the Bandar Abbas Hinterland

A remarkable characteristic of the Bandar Abbas Hinterland is the frequent presence of oil seepages that can serve as an indicator of probable oilfields in the region. The Seeps A and B are located in the main Zagros Suture Zone, 150 km to the northeast of Bandar Abbas and 30 km to the west of the same city, respectively. The presence of well-known Paleozoic source rocks (e.g., Seyahou, Sarchahan, and Gurpi formations) in the vicinity of the mentioned oil seepages shows that the seeping oil is coming from an oil source. The present research is aimed investigating the petroleum system and determining the source of the mentioned oil seepages. Results of the Rock-Eval analyses showed that the samples of the Seyahou Formation are thermally overmatured, making them exhibit inadequate oil generation potential. These samples contain Type-III kerogen and were found to be in the metagenesis stage. However, compared to other formations, Sarchahan and Gurpi exhibited good hydrocarbon generation potentials. On the other hand, based on the PI – Tmax diagram, the Sarchahan Formation was found to be in the early oil and condensate production window (i.e., catagenesis stage) while the Gurpi Formation was seen to be immature. Biomarker analysis results showed that the samples were deposited in a mixed marine environment and contained Type-II and Type II/III kerogen. The reason behind the occurrence of the oil seepages in an oxidative environment could be the sever impact of the biological degradation. The stable carbon isotope composition of the crude samples supported the biomarker data in general. Therefore, it can be concluded that the studied oil seepages were probably sourced from the Sarchahan Formation.

Study on the kinetic analysis and pyrolysis evolution in transition zone of metal salt catalyzed steam injection in-situ maoming oil shale upgrading

In order to study the kinetic characteristics and pyrolysis evolution in the transition zone of oil shale during metal salt catalyzed steam in-situ production, the oil shale and semi-cokes under different heating conditions were studied by using a self-made reactor and various analysis methods. The results show that the pyrolysis temperature of semi-cokes in the transition zone increases gradually from front to back, the mass loss in the front is greater than that in the back, and the activation energy is less than that in the back. Compared with conventional and steam heating, metal salt catalyzed steam heating enlarges the activation energy difference between the front and back of the transition zone. With the increase in pyrolysis temperature, the aliphatic content in the transition zone decreased rapidly. The front of the transition zone is the main oil and gas generation area, and the oil and gas generation potential in the back is significantly reduced. Metal salt catalyzed steam heating accelerates the pyrolysis and release of aliphatic groups and reduces the degree of aliphatic branching in the transition zone. During the initial pyrolysis, the oxygen-containing functional groups and aromatic structures in the transition zone decreased, and then increased with the increase of pyrolysis temperature. The content of oxygen-containing functional groups in the transition zone of metal salt catalyzed steam heating is generally higher than that of conventional and steam heating, while the content of aromatic structures is generally low, indicating that their interaction increases the oxidation effect, promotes the pyrolysis and release of aromatic structures, and inhibits the condensation of aromatic structures. In the presence of potassium feldspar, the high temperature accelerates the illitization of kaolinite in oil shale, and there is basically no potassium feldspar and pyrite in the back of the transition zone. Compared with metal salt catalysts and steam, temperature is the most important factor affecting the pyrolysis of inorganic minerals in oil shale and semi-cokes.

Contrasting shale oil accumulation in the upper and lower sweet spots of the lacustrine Permian Lucaogou Formation, Junggar Basin, China

Shale oil enrichment and accumulation in lacustrine strata is rather heterogeneous (unlike that in marine strata), which is a challenging issue to study. Here we carried out a case study in the Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, northwestern China. Based on data from drill cores, thin sections, rock extracts, and crude oils (including well logging, petrophysics, nuclear magnetic resonance, organic geochemistry, and oil test), the differences of lithology, reservoir physical property, oil generation potential, shale oil content, and physical property and geochemistry of oil between the lower and upper sweet spots were comprehensively compared. Results show that a mixed sedimentary system comprising interbedded carbonate, siltstone, and mudstone was developed owing to terrigenous clastic sedimentation, volcanism, and carbonate deposition. The lower sweet spot has a relatively higher content of silt compared with the upper sweet spot. Due to spatial changes in the depositional environment, only the lower sweet spot occurs at the northeastern margin of the study area and only the upper sweet spot occurs at its southeastern margin, but both occur in the central part of the study area. The porosity and permeability of the sweet spots are highly heterogeneous, due to the complex sedimentary–diagenetic processes, and dissolution pores are common in the lower sweet spot. The hydrocarbon generation potential and shale oil content of the sweet spots are both excellent. Comparatively, the shale oil in the lower sweet spot has higher densities and lower wax contents than those in the upper sweet spot. Thus, the shale oil is more mobile in the upper sweet spot. This implies a high-salinity depositional environment for the lower sweet spot and the oils are generated from salt-tolerant planktonic algae. The oil saturation index (OSI) values are not entirely consistent with the test production results. This indicates that the shale oil productivity is comprehensively controlled by multiple factors, e.g., the hydrocarbon generation potential, reservoir physical properties, and shale oil mobility. These are key features that distinguish lacustrine from marine shale oil systems. The exploration and exploitation strategies of shale oil in lacustrine systems need to be carefully developed.

Characterization of Lower Cretaceous organic-rich shales from the Kom Ombo Basin, Egypt: Implications for conventional oil generation

• The shales of the Kom Ombo Formation are organic-rich sediments, with TOC value of up to 6.61 wt.%. • The organic facies are predominantly of Types II and II/III kerogen. • Kom Ombo shales were deposited in a marine under anoxic environmental conditions. • The shales reached peak oil-window and generated commercial amounts of oil. This study uses organic geochemical and petrographic analyses to characterise the organic-rich shales from the Lower Cretaceous Kom Ombo Formation in the Kom Ombo Basin. The overall results show that the Kom Ombo shales are considered to have good petroleum source rock potential with total organic carbon (TOC) content > 1 wt % and hydrocarbon yields of up to 27.62 mg hydrocarbons/g rock. Based on lipid biomarker ratios and carbon isotopes, the Kom Ombo shale contains a blend of organic matter derived primarily from algal marine and other aquatic organic matter, with some terrigenous land plants, deposited under anoxic conditions. These findings of organic matter (OM) input and depositional conditions are consistent with the high TOC content of up to 6.61 wt. % and mainly Types II and II/III kerogen, with small amounts of Type III kerogen, thus yielding both oil and gas, with oils of high to low wax contents. The geochemically determined dominance of oil generation potential is in agreement with the findings of considerable concentration of fluorescent liptinite macerals. The chemical and optical maturity results show that the majority of the examined Kom Ombo shale samples have entered the main stage of oil generation, exhibiting a range of early-mature to late-mature. Therefore, as highlighted in this study, the oil generation potential of the Kom Ombo shales may represent future conventional petroleum exploration opportunities.

Geochemistry and organic petrology of the bituminite shales from the Kapurdi mine, Rajasthan of NW India: implications for waxy oil generation potential

This study examines the geochemical and petrographic characteristics of seven bituminite shales from the Kapurdi mine in the Rajasthan, NW India, in order to assess their organic matter inputs and evaluate the oil-prone potentials. These bituminite shale samples exhibit high total organic carbon (TOC) content (up to 45.11 wt.%). The high TOC contents were correlated with low total sulfur content of less than 1 wt.% and suggest that these bituminite shales were deposited in a fresh lacustrine environment. The dominance of such lacustrine environmental setting was confirmed by the presence of the Botryococcus algae. The analyzed bituminite shales are characterized by a bimodal distribution of normal alkanes and relatively low isoprenoid Pr/Ph, Pr/n-C17 and Ph/n-C18 ratios. These characteristics suggest that these bituminite shales contain a blend of organic matter that was derived primarily from algal lacustrine and other aquatic organic matter, with terrigenous land plants and deposited under suboxic to anoxic environmental conditions. Such findings of the organic matter (OM) input and environmental conditions are consistent with mainly Types I and II kerogen and small amounts of Type II/III kerogen, thus yielding both oil and gas prone to higher concentrations of oil generation potential. The dominance of hydrogen-rich kerogen and oil generation potential is in agreement with the findings of high hydrogen index (HI = 240–425 mg HC/g TOC) and H/C atomic ratio of more than 1.20. The abundance of n-alkene and n-alkane doublets in the pyrolysis–gas chromatography (Py–GC) also indicates that these bituminite shales have potential to generate high concentrations of paraffinic waxy oil. Most of the maturity indicators show that the bituminite shales from the Kapurdi mine have not yet entered the main stage of oil generation window, exhibiting a range of immature stages. Therefore, as highlighted in this study, these bituminite shales can be considered as a good candidate for oil shale reoterting processes to release commercial amounts of oil upon using artificial heating techniques such as hydrothermal conversion.

Geochemical and Petrological Characterization of the Early Eocene Carbonaceous Shales: Implications for Oil and Gas Exploration in the Barmer Basin, Northwest India.

Carbonaceous shales of the Early Eocene Dharvi/Dunger Formation in the onshore Barmer Basin, northwest India were studied for the first time by integrating geochemical and organic petrological analyses. The carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are characterized by a higher organic carbon content (TOC) of >10 wt % and consist mainly of a mixture of organic matter of types II and III kerogen, with exhibited hydrogen index values ranging between 202 and 292 mg HC/g TOC. The dominance of such kerogen is confirmed by the high amounts of huminite and fluorescent liptinite macerals. Consequently, the carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are promising source rocks for both oil and gas generation potential, with oils of high wax contents, according to pyrolysis-gas chromatography results. The chemical and optical maturity results such as low values huminite/vitrinite reflectance, production index, and T max show that most of the examined carbonaceous shale rocks from the outcrop section of the Kapurdi mine have entered the low maturity stage of oil generation, exhibiting a range of immature to the very early-mature. Therefore, as highlighted in this study, the substantial abundance in hydrocarbon generation potential from these carbonaceous shales in the Dharvi/Dunger Formation may represent future conventional petroleum exploration in the southern part of the Barmer Basin, where the Dharvi/Dunger Formation has reached deeper burial depths.

Geochemical, mineralogical and petrographical characteristics of the domanik formation from north samara region in the volga-ural basin, Russia: Implication for unconventional tight oil reservoir potential

This paper comprehensively analyzes the geochemical, mineralogical and petrographical properties combined with bulk kinetics modeling of the Domanik organic-rich carbonate from various depth intervals in Kuzminovsky oilfield (well № 26 R), Volga-Ural Basin, Russia. The results show that, the Domanik carbonate-rich samples are characterized by high content of the total organic matter (TOC) up to 13.31 wt %, and contain mainly Type II kerogen with a slight II/III kerogen type, reaching very good to excellent oil generation potential. Moreover, the studied samples contain hydrogen-rich kerogen, which expected to generate paraffin, naphthene and aromatic (P–N-A) oil with low wax content as demonstrated by the Py-GC Pyrolysis combined with the abundance of fluorescent alginite, amorphous organic matter, and bituminite as established from investigations via microscope. The maturity indicators demonstrated that, most of the examined Domanik carbonate-rich samples, with a burial depth between 1726.5 m and 1784.9 m, have generally reached low thermal maturity stages; thus, defining an immature to moderate-mature of oil generation window. The results of the kinetic models suggested that, Domanik carbonate-rich rocks with vitrinite reflectance (VRo) values in the range of 0.60–0.71%, have reached relatively low kerogen transformation ratio in the range of 10–20%, indicating low probability oil generation. These finding are confirmed by the presence of low oil saturation index of less than 100 mg HC/g rock (19.64–69.97). In addition, the results of thin section, scanning electron microscopy (SEM) and micro-computed tomography (micro-CT) showed that the studied samples are characterized by low porosity (up to 3.29%) with a wide pores size range, including interparticle, cavities, cracks and organic matter pores. The development of these pore types and their quality in the studied samples is mainly controlled by high mineralogical brittleness (i.e., carbonate and quartz) together with the high organic matter inputs. Therefore, according to the obtained results, characteristics and observations, the Domanik Formation has a high potential for commercial oil production, which typically requires hydraulic fracturing followed by an in-situ retort, mainly by thermal methods such as steam injection and in situ combustion process.

Hydraulic fracturing as unconventional production potential for the organic-rich carbonate reservoir rocks in the Abu El Gharadig Field, north western Desert (Egypt): Evidence from combined organic geochemical, petrophysical and bulk kinetics modeling results

This paper systematically analyzes the organic geochemical, petrophysical, and petrographical properties combined with bulk kinetics modeling of the Abu Roash (F) organic-rich carbonate rocks in the Abu El Gharadig Field. The Abu Roash (F) carbonate-rich samples exhibit high organic content with total organic matter (TOC) values up to 3.04 wt%, and mainly Type II kerogen, with a slight gradient to Type II/III and III kerogens, reaching good to very good oil generation potential. This finding of hydrogen-rich kerogen and oil generation potential was also demonstrated by the abundance of fluorescent alginite, amorphous organic matter (AOM), and bituminite organic matter (OM) as established via ultra violet (UV) light microscopy. The maturity indicators demonstrate that most of the examined Abu Roash (F) carbonate-rich samples from the studied wells, with a deep burial depth of more than 3000 m, are thermally mature, thus defining an early mature to moderate-mature stage. The kinetic models suggest that the Abu Roash (F) carbonate-rich rocks in the deepest burial depth, with calculated vitrinite reflectance (%VRo) values in the range of 0.72–0.83 %, have reached kerogen transformation ratio (TR) in the range of 10–55 %, indicating a high probability of oil production. This finding is confirmed by the presence of the oil crossover in these rocks with an oil saturation index (OSI) of more than 100 mg HC/ g rock. The Abu Roash (F) organic-rich carbonates are intractable rocks as implied by low porosities (up to 2.33 %) and poor permeability in the range of 0.0017–0.0039 mD. The pores in these rocks have a wide range in size, including interparticle, fracture, and organic matter (OM) pores, as recognized in the thin section and scanning electron microscopy (SEM). The development of these pore types and their quality is mainly controlled by high mineralogical brittleness (i.e., carbonates) together with the high OM inputs. Based on the above characteristics, the Abu Roash (F) carbonate-rich rocks in the Abu El Gharadig Field are a candidate for unconventional tight oil reservoir potential, which typically require a form of hydraulic fracturing for possible oil production at deeper burial depths.

Experimental investigation on the pyrolysis process and product distribution characteristics of organic-rich shale via supercritical water

Low-medium maturity organic-rich shale reservoirs have garnered increasing attention due to their enormous oil and gas generation potential. In this study, the pyrolysis conversion process and product distribution characteristics of shale core samples via supercritical water (SCW) were investigated. The yield of shale oil increased from 4.5 wt% at 385 °C to 15.13 wt% at 425 °C, with the maximum formation rate of shale oil ranging from temperatures of 405 °C to 425 °C. The thermal bitumen reached 15.11 wt% at 405 °C before rapidly decreasing to 3.2 wt% at 425 °C. In the pyrolysis process of shale cores via SCW, the intermediate thermal bitumen produced by thermal cracking of kerogen was retained in the cores and continued to be decomposed into shale oil and gas with the increase of SCW temperature. Simultaneously, a large number of pores were formed in the core matrix due to the massive decomposition of kerogen and thermal bitumen. The increase in SCW temperature greatly decreased the heavy components as well as increased the light components in shale oil. Additionally, aliphatic hydrocarbon cracking or Diels-Alder type aromatization reactions resulted in an increase in aromatic hydrocarbons and a decrease in the H/C atomic ratio of shale oil. Raising SCW temperature increased the content of C2-C5 hydrocarbon gases and the alkenes/alkanes ratio, which was related to the secondary cracking. The important findings of the pyrolysis conversion process and product distribution characteristics of shale cores via SCW not only enrich the theoretical basis in this area, but also provide strong support for the use of SCW in the in-situ conversion of low-medium maturity organic-rich shale reservoirs.

Spatiotemporal quantification of organic matter accumulation in the Eocene Green River Formation, Bridger Basin, Wyoming

It has long been recognized that lakes can bury large amounts of organic carbon (CORG) in their sediment, with important consequences for conventional and unconventional petroleum resources and potentially for the global carbon cycle. The detailed distribution of lacustrine organic carbon through space and time is important to understanding its commercial and climatic implications, but has seldom been documented in detail. The Green River Formation offers a unique opportunity to improve this understanding, due to extensive Fischer assay analyses of its oil generative potential and to recently published radioisotopic age analyses of intercalat ed volcanic tuffs. Fischer assay analyses reveal distinctly different patterns of organic matter enrichment that correlate with different lacustrine facies associations. Histograms of oil generative potential for evaporative facies of the Wilkins Peak Member exhibit an approximately exponential distribution. This pattern is interpret ed to result from episodic expansion and contraction of Eocene Lake Gosiute across a low-gradient basin floor that experienced frequent desiccation. In contrast, histograms for fluctuating profundal facies of the upper Rife Bed of the Tipton Member and the lower LaClede Bed of the Laney Member exhibit an approximately normal or log normal distribution, with modes as high as 16–18 gallons per ton. This pattern is interpreted to reflect generally deeper conditions when the lake often intersected basin-bounding uplifts. Within the Bridger basin, burial of CORG was greatest in the south during initial Wilkins Peak Member deposition, reflecting greater rates of accommodation near the Uinta uplift. The locus of CORG burial shifted north during upper Wilkins Peak Member deposition, coincident with a decrease in differential accommodation. CORG burial during deposition of the upper Rife and lower LaClede Beds was greatest in the southeast, due either to greater accommodation or localized influx of river-borne nutrients. Average CORG burial fluxes are consistently ~4-5 g/m2 yr for each interval, which is an order of magnitude less than fluxes reported for small Holocene lakes in the northern hemisphere. Maximum rates of CORG burial during deposition of organic-rich mudstone beds (oil shale) were likely similar to Holocene lakes however. Deposition of carbonate minerals in the Bridger basin resulted in additional, inorganic carbon burial. Overall it appears that carbon burial by Eocene lakes could have influenced the global carbon cycle, but only if synchronized across multiple lake systems.

The effect of supercritical water on conversion of resins, asphaltenes and kerogens in rocks of different lithofacies of Domanic deposits of Tatarstan

In this paper the effect of supercritical water (SCW) at 374 °C and 22.4–24.6 MPa on the conversion of resins, asphaltenes, and kerogens in rocks of different lithofacies of Domanic deposits of Romashkino, Tavely and Bavly oilfields of Tatarstan was discussed. A feature of the rocks is the different content of organic carbon (7.07, 1.90 and 0.33 %, respectively), the high content of resins and asphaltenes (over 60 % in total) and the presence of type II kerogen with a high oil generation potential. The SCW treatment of the rocks leads to the decomposition of kerogens and the destruction of resins and asphaltenes with the formation of petroleum hydrocarbons. The conversion of resins, asphaltenes, and kerogens is accompanied by the alkyl substituents detachment, which leads to a decrease in the length and degree of aliphatic fragments branching and an increase in the aromatic carbon content. The oxygen-containing groups decrease in kerogens and asphaltenes and increase in resins, indicating the occurrence of degradation and oxidation processes. Destructive processes lead to an increase in the degree of catagenic maturation of kerogens, which is accompanied by partial desulfurization and demetalization of their structure, as well as of asphaltenes and resins. In kerogens, asphaltenes and resins of carbonate-siliceous rocks of the Romashkino and Tavely oilfields the concentration of biogenic microelements (ME) decreases with their subsequent adsorption on the mineral surface of the rocks, in this case, the content of radioactive ME noticeably increases, especially in resins. Under similar conditions of SCW exposure on carbonate rock of the Bavly oilfield as well as high-carbon rocks in kerogen, the concentration of biogenic ME decreases and the concentration of radioactive ME increases, but unlike them, the concentrations of biogenic, radioactive and rare-earth ME increase in asphaltenes and resins, with a decrease in their content in rocks. The identified distinctive features of the conversion of resins, asphaltenes and kerogens of Domanic rocks of different lithofacies, which affect the quality of oil extracted from these rocks, must be taken into account when developing deposits using SCW technologies.

Compositions, structures, and confined pyrolysis of the alga Chlorella and its nonhydrolyzable fractions

Nonhydrolyzable organic carbon (NHC) fractions were isolated from commercial Chlorella using trifluoroacetic acid (TFA), sodium periodate (SP), ball mill (MES), and ball mill-sodium periodate (BSP) methods. The structures and relationships of the fractions with oil and gas production potentials (OGP) were investigated by solid-state 13C Cross Polarization/Total Sideband Suppression (CP/TOSS) NMR spectroscopy techniques and by confined pyrolysis. The results demonstrated that the TFA and SP fractions exhibited the highest polymethylene carbon contents and the lowest proportions of polar materials. Both bulk Chlorella and the NHC fractions had considerable oil and gas generation potential. The hydrogen indices evaluated by Rock-Eval analysis were highly significantly correlated with the OGP values estimated for the NHC fractions from the NMR methods. In addition, the oil and gas generated from the Chlorella sample and its NHC fractions were dominated with primary pyrolysis products. The contents of total n-alkanes (n-C6–33) of the pyrolysates increased with increasing pyrolysis times. The n-alkanes of the TFA, SP, and BSP fraction pyrolysates were dominated by mid chain-length components (n-C15, n-C17, and n-C23). Moreover, the SP fraction exhibited high NHC yield and OGP value, and low contents of nitrogen and oxygen. This study significantly improves our understanding of the bio-oil generation potential of this green alga.

Optical and geochemical assessment of petroleum source rock potential and palaeodepositional environments of Cretaceous mudstones, Koum Basin, North Cameroon

Limited organic matter (OM) characterisation studies on Cretaceous mudstone successions in the Koum Basin have resulted in a significant knowledge gap in the source rock potential; a petroleum system prerequisite. Field mapping and lithofacies analysis of outcrop sections point to fluvial channel and marginal to profundal lake deposits. Representative mudstone samples were evaluated using multiproxy organo-petrographic and bulk geochemical analyses to assess the kerogen type, thermal maturity, hydrocarbon generation potential, and deduce the paleodepositional environment. Results reveal that ∼90% of the samples are organic-lean and ∼10% organic-rich with TOC content of 2.81–6.91 wt%. Rock-Eval pyrolysis S2 yields of 14.50–54.18 mg HC/g rock and hydrogen index (HI) 784–846 mgHC/gTOC, suggest excellent potential for oil generation. High S1 values of 1.18–1.45 mg HC/g rock and low production indices (PI) of 0.02–0.03 indicate in situ generated free hydrocarbons. PI and Tmax of 438°C–443 °C, consistent with measured vitrinite reflectance (Ro% = 0.28–0.53%), Spore Colour Index (SCI = yellow to golden brown) and Thermal Alteration Index (TAI = 1.5 to 2.6) on the Chevron scale, portraying an immature to marginally mature OM. Oil-prone kerogen Type I-II dominates and to a lesser extent gas-prone Type III, derived from algal-terrestrial organic facies, typified by the predominance of amorphous OM 51.2%, liptinites 24.6%, vitrinite 16.4% and inertinite 7.8%. Based on lithofacies, and palynological evidence, a fluvio-lacustrine depositional setting with limited marine influence, under fluctuating warm humid to hot semi-arid paleoclimates, is inferred. A comparison with surrounding petroleum-producing basins further enhances the understanding of the Koum Basin's hydrocarbon potential within the West Central African rift system context.

Oil migration, retention, and differential accumulation in “sandwiched” lacustrine shale oil systems from the Chang 7 member of the Upper Triassic Yanchang Formation, Ordos Basin, China

To extract hydrocarbons from unconventional shale systems, it is necessary to assess oil retention and accumulation. This study presents experimental findings on oil retention, migration, and accumulation in a lacustrine shale system from the Chang 7 member of the Upper Triassic Yanchang Formation, Ordos Basin. 68 core samples were collected from the target layer to investigate the migration behavior of trapped hydrocarbons by organic geochemical, petrological, and petrophysical methods. The amount of oil retention and generation potential was determined using total organic carbon and programmed pyrolysis analysis. The pore structure and pore connectivity were quantified using scanning electron microscopy and micro-computed tomography scanning. Shale samples were also fractionated to determine the chemical composition of extracted hydrocarbons using a ternary azeotropic solvent extraction system. The effects of lithofacies, mineral compositions, organic matter, and pore structure on oil retention and accumulation were studied based on these findings.The findings revealed that lithofacies have a significant impact on the composition and amount of oil stored in the “sandwiched” shale systems. As oil is sorbed by organic matter, organic-rich shale lithofacies retain a large amount of oil. However, due to the developed dissolution-related pores in feldspar, the interbedded organic-lean siltstones have a higher oil saturation index and contain more free oil. Pore diameters and pore connectivity are also larger in the thin organic-lean siltstones. Shale oil intrasource migration and charging are observed in the Chang 7 member lithofacies assemblages during primary migration: oil is generated in organic-rich source rocks and expelled in short distances to adjacent siltstones. The thin organic-lean siltstones act as reservoir units for petroleum that has migrated from organic-rich shale units. Simultaneously, oil in thin siltstone intervals enriches in aliphatic and aromatic compounds, while petroleum from source rocks enriched in asphaltenes and resins, due to migration fractionation. This research shows oil migration and differential accumulation in the “sandwiched” shale systems in the Chang 7 member of the Upper Triassic Yanchang Formation, enhancing our knowledge of shale oil accumulation.

Heterogeneity of alkaline lacustrine source rocks of the lower Permian Fengcheng Formation in the Mahu Sag, Junggar Basin, northwestern China

The alkaline lacustrine source rocks in the lower Permian Fengcheng Formation in the Mahu Sag, Junggar Basin, China, exhibit significant heterogeneity. However, most previous studies have focused on the vertical variability of the source rocks, and the lateral variability is poorly understood. This study investigated recently drilled samples of the Fengcheng Formation in the Manan area to assess the lateral variability of the source rocks. The geochemical characteristics of the Fengcheng Formation source rocks in the Manan area are variable, with low–high abundances of organic matter, which comprises types I–III kerogen that is mature to high-mature. These features differ from the typical Fengcheng Formation source rocks in the Wuxia–Fengcheng area, which have a high abundance of organic matter with substantial hydrocarbon and shale oil generation potential. Biomarker data show that the organic matter in the Fengcheng Formation source rocks in the Manan area is a mixture of higher plants, algae, and bacteria, which differs from the Wuxia–Fengcheng area where algae and bacteria are dominant. The Fengcheng Formation source rocks in the Manan area were deposited in an oxic to anoxic environment characterized by large variations in water salinity and stratification. Mudstones were deposited rather than carbonate rocks. This differs from the strongly reducing, hypersaline, and water-stratified depositional environment of the Fengcheng Formation source rocks in the Wuxia–Fengcheng area. These two areas are separated by the Dazhuluogou Fault, and there are no alkaline lacustrine deposits in the Manan area. The distribution of the alkaline lacustrine source rocks was controlled by the paleogeography and sedimentary environment, which was characterized by significant spatial heterogeneity.

Comparative Study of Tectonic Evolution and Oil–Gas Accumulation in the Ri-Qing-Wei Basin and the Jiaolai Basin

The Ri-Qing-Wei basin is located in the central Sulu Orogeny on the eastern side of the Tanlu fault zone in eastern Shandong province. To the north, the Jiaonan uplift separates it from the Jiaolai basin, where drilling in the lower Cretaceous sedimentary rock of the Laiyang group has indicated good oil and gas reserves. Drilling in the Ri-Qing-Wei basin, in contrast, is in the preliminary exploration stage. Lingke 1, the only scientific well, is on Lingshan Island on the basin boundary, and it encountered a large set of source rocks 700 m thick. The two basins were comprehensively compared and analyzed based on comprehensive fieldwork, drilling, core data, seismic profiling, sedimentary filling sequence, tectonic evolution history, basin burial history, geothermal history, and geochemical characteristics of the source rocks. The results showed three things: (1) from the late Jurassic to the early Cretaceous (the Laiyang period), subduction of the paleo-Pacific plate under the Eurasian plate delaminated the lithospheric mantle of the Sulu Orogeny, thus forming a series of passive continental rift basins. Of these, the Ri-Qing-Wei is central and the Jiaolai is its branch. After the active rift stage in the Qingshan period and the depression stage in the Wangshi period, the burial depth of the source rocks in the Ri-Qing-Wei basin was up to 6000 m, while the maximum burial depth in the Jiaolai basin was about 3000 m. The paleogeotemperature of both basins exceeded 125 °C, indicating that the source rocks were very mature. (2) A comprehensive comparison of their geochemical characteristics—organic matter abundance, type, and maturity—showed that both basins have oil-generating potential. It is worth noting that the magmatic activity in the Qingshan period had a positive effect on the evolution of the source rocks but was not the key factor: burial depth was. (3) Oil and gas failed to accumulate in the Jiaolai basin because they were destroyed by the lateral tectonic activities. During the right-lateral strike-slip stage (50 ± 5 Ma) during the late Wangshi, the Jiaolai basin was strongly uplifted over a range of more than 1000 m by the Tanlu and Wulian-Mouji fault zones along the boundary. The Wangshi group, as a cap rock, was eroded, and oil and gas overflowed along the fault that reached the surface. The late Wangshi period uplift of the Ri-Qing-Wei basin was less than 1000 m because the source rock was deeper, and the reverse faults in the basin were sealed well. The uplift did little damage to the oil in the Ri-Qing-Wei basin. Above all, tectonic evolution was the main controlling factor of oil accumulation in the study area, and the layers of the Laiyang group in the Ri-Qing-Wei basin have oil and gas potential, making it a prospective target for unconventional offshore oil and gas exploration.

Sinian tectonic evolution and distribution of source rocks in northwest Tarim Basin, China

Tarim Basin experienced several tectonic events during Precambrian, including the Neoproterozoic Rodinia supercontinent assembly/breakup event and Snowball Earth, and has great potential for oil generation in the ultra-deep deposits. The Precambrian strata in the northwest margin of the Tarim Basin (abbreviated as the northwest Tarim) are well exposed, which play a key role for understanding the tectonic evolution of Neoproterozoic. The northwest Tarim underwent the transformation that tectonic setting changed from convergence to expansion in the Neoproterozoic, and finally formed a continental rift until 572 Ma. During this period, thick layer of black mudstone was deposited, which probably was the important petroleum source rock. The TOC of Sinian mudstones is between 0.32 and 1.25%, with an average value of 0.53%. The average of rock pyrolysis parameters (S1+S2) is 0.17 mg/g, Ro is between 1.61% and 2.52%, and the average of chloroform asphalt "A" is 0.0076%. These geochemical characteristics indicate that the source rocks are now highly mature. The carbon isotopes of kerogen are between −27.2‰ and −30.2‰ and biomarkers show that algae and bacteria are the main source input, therefore, the Sinian source rock mainly contains marine type I kerogen from a single source. The above data show that the Sinian source rock is a set of effective source rocks. The tectonic evolution of northwest Tarim was reconstructed based on the age characteristics of detrital zircons, and it indicated that the Sinian source rocks were controlled by continental rift deepening and large-scale transgression. Combined with seismic reflection characteristics, the distribution of Sinian source rocks are shown, which provides an important basis for Precambrian oil and gas exploration.