Source Rock Reservoir Research Articles

Effects of organic richness, mineral composition, diagenesis, and thermal maturity on the viscoelastic properties of organic-rich Cretaceous mudstones in the Middle Magdalena Valley basin, Colombia

A major geological risk factor for engineering and energy-related applications, such as CO2 storage and unconventional hydrocarbon production, is the geomechanical integrity of mudrocks. The goal of this work is to better constrain the macroscopic mechanical properties resulting from microstructural components by investigating the effects of thermal maturity, mineral composition, diagenesis and organic richness on the mechanical properties of Cretaceous mudstones in two surface sections (San Vicente de Chucurí and La Cristalina Creek) and one well (La Luna-1) from the Middle Magdalena Valley Basin (MMVB), Colombia. The thermal maturity of 22 rock samples was evaluated via organic source-rock screening and determination of illite crystallinity (Reichweite). Both geothermometers placed the La Luna Formation rock samples from San Vicente de Chucurí and the La Luna-1 well within the oil generation window (80°C–120 °C). In contrast, the rock samples of the Guaguaquí Group from La Cristalina Creek in the southern part of the basin are within the gas window (>180 °C). The mineralogy of organic-rich mudstones in the MMVB is dominated by quartz and calcite. Moreover, mudstones from the MMVB have a wide range of organic richness and clay contents, with organic abundances comparable to and clay contents lower than those found in other source-rock reservoirs. The Young's modulus (EIT), Martens hardness (HM), and creep (CIT), as determined through microindentation experiments, highly varied, but overall, the findings suggest that the Cretaceous rocks of the MMVB present conditions favorable for hydraulic fracturing. Furthermore, the viscoelastic properties of Cretaceous rocks in the MMVB are influenced primarily by the concentrations of strong minerals (quartz and calcite) and weak components (clay and TOC). Specifically, an increase in the concentration of weak components compared with that of strong minerals leads to an increase in CIT and a decrease in HM and EIT, and vice versa. Unlike other source-rock reservoirs, there are no indications of a strong correlation between thermal maturity and mechanical properties, suggesting a decoupling of these parameters in rocks of the MMVB. A close scanning electron microscopy examination of the rocks indicated that the observed weak to moderate correlation between thermal maturity and mechanical properties appears to result from rock silicification and calcite cementation caused by the precipitation of these minerals at early stages of diagenesis. This observation implies that the impact of diagenesis on rock geomechanics of silica-rich and calcareous-rich mudstones may override or be more important than the effects of thermal maturity, which, along with clay and organic matter contents, are the greatest controls in the geomechanics of argillaceous source-rock reservoirs.

Insights on Using Solid Bitumen Reflectance as a Thermal Maturity Proxy in the Bakken Formation, Williston Basin, USA.

To further refine the use of solid bitumen reflectance (BRo in %) as a measurement of thermal maturity in source-rock reservoirs, we examined its relationship to other thermal proxies in the Bakken Formation. Comparisons included criteria from programmed temperature pyrolysis, gas chromatography (GC), and Fourier transform infrared (FTIR) spectroscopy. Thirty-two organic-rich samples from the lower and upper shale members of the Devonian-Lower Carboniferous Bakken Formation were collected from eight cores across the Williston Basin, USA, at depths (∼7575-11,330 ft) representing immature through post peak oil/early condensate thermal maturity conditions based on proximity to current hydrocarbon production. Unmodified BRo values were correlated to programmed temperature pyrolysis parameters (hydrogen index, production index, and T max), normal hydrocarbon and isoprenoid analysis of extractable organic matter (pristane/n-C17 and phytane/n-C18) from GC analysis, and peak ratios from FTIR spectroscopy (branching ratio and A-factor). Strong correlations between unmodified BRo values (not corrected to a vitrinite reflectance equivalent, VRe) and other thermal proxies suggest that BRo can be used as a direct thermal proxy in marine Paleozoic source-rock reservoirs where vitrinite is rare or absent. Moreover, an apparent overestimation of VRe at the lowest thermal maturity investigated herein may argue against the application of BRo conversion to VRe in the Bakken Formation. Solvent extraction caused a consistent decrease in BRo when average post-extraction values from a given well were compared to BRo prior to extraction, although the decrease in mean value was not statistically significant. These results are discussed in the context of advocating for the use of unmodified BRo values as a best practice for thermal maturity determination in Paleozoic marine source-rock reservoirs.

The magma plumbing system of the Northern Carnarvon Basin, offshore Australia: multiscale controls on basin-wide magma emplacement, and implications for petroleum exploration

Abstract The Northern Carnarvon Basin (NCB) located on Australia's North West Shelf hosts an extensive (∼40 000 km 2 ) intrusive igneous complex related to Mesozoic rifting and break-up. Using an extensive suite of modern 3D seismic reflection surveys, we have mapped this intrusive system across the NCB. We identify three predominant intrusion morphologies: stacked sheets of large interconnected sill intrusions (up to ∼170 km long) and smaller (8–30 km long) isolated, strata concordant intrusions, which often interact with normal faults emplaced into deltaic sedimentary rocks, and variably sized (10–40 km long) saucer-shaped intrusions emplaced into marine shales, spread across seven zones (geographically constrained groups of intrusions of a specific morphology). We consider the zones’ margin-parallel orientation, suggesting control by subcrustal extensional processes during rifting, and the variation in intrusion morphology between these zones, suggesting a dominant control by host rock mechanical properties. We integrate previous work with our observations, constraining emplacement to between the Kimmeridgian and Valanginian, coinciding with key phases of margin evolution. Finally, we assess the impact of this intrusive complex on local petroleum systems. There is likely little to no adverse impact on source rock maturation or reservoir contamination by CO 2 , but there is a spatial dissociation between the location of groups of intrusions and the gas fields, particularly in the Exmouth Plateau. This suggests that migrating hydrocarbons may be blocked, baffled and/or redirected by emplaced igneous rocks.

Quantifying the Pore Heterogeneity of Alkaline Lake Shale during Hydrous Pyrolysis by Using the Multifractal Method

Distinguishing itself from marine shale formations, alkaline lake shale, as a significant hydrocarbon source rock and petroleum reservoir, exhibits distinct multifractal characteristics and evolutionary patterns. This study employs a combination of hydrous pyrolysis experimentation, nitrogen adsorption analysis, and multifractal theory to investigate the factors influencing pore heterogeneity and multifractal dimension during the maturation process of shale with abundant rich alkaline minerals. Utilizing partial least squares (PLS) analysis, a comparative examination is conducted, elucidating the disparate influence of mineralogical composition on their respective multifractal dimensions. The findings reveal a dynamic evolution of pore characteristics throughout the maturation process of alkaline lake shale, delineated into three distinct stages. Initially, in Stage 1 (200 °C to 300 °C), both ΔD and H demonstrate an incremental trend, rising from 1.2699 to 1.3 and from 0.8615 to 0.8636, respectively. Subsequently, in Stages 2 and 3, fluctuations are observed in the values of ΔD and D, while the H value undergoes a pronounced decline to 0.85. Additionally, the parameter D1 exhibits a diminishing trajectory across all stages, decreasing from 0.859 to 0.829, indicative of evolving pore structure characteristics throughout the maturation process. The distinct alkaline environment and mineral composition of alkaline lake shale engender disparate diagenetic effects during its maturation process compared with other shale varieties. Consequently, this disparity results in contrasting evolutionary trajectories in pore heterogeneity and multifractal characteristics. Specifically, multifractal characteristics of alkaline lake shale are primarily influenced by quartz, potassium feldspar, clay minerals, and alkaline minerals.

Determine Oil and Water Saturations in Preserved Source Rocks From 2D T1-T2 NMR

Two-dimensional (2D) T1-T2 NMR has been widely proposed as a method to determine the fluids present in unconventional source rocks. However, the assignment of the components in the 2D T1- T2 NMR spectra has so far been based on conceptual consideration and lacks rigorous experimental verification. Many assignment variations appeared in the literature and can be misleading. For example, large T1/T2 peaks in the 2D T1-T2 NMR were suggested to be fluid in small pores coupled with kerogen solid through dipolar relaxation. Our recent 500-MHz NMR relaxation experiments found that the dipolar relaxation between nanoconfined fluids and solid matrix is not big enough to support that large T1/T2 interpretation. The objective of this paper is to determine what quantitative data can be obtained using 2D T1-T2 NMR from source rocks with high confidence. We found the oil and water saturation can be accurately measured in preserved source rock plugs. Two-dimensional T1-T2 NMR data were collected on preserved core plugs from five wells of a source rock reservoir using an inversion-recovery Carr-Purcell-Meiboom-Gill (CMPG) pulse sequence on a 12-MHz NMR instrument. The acquired 2D data were inverted using an optimized inversion software, MUPen2D. We then obtain oil and water content in the plug from the 2D T1-T2 NMR using an in-house-developed NMR MATLAB app. The porosity of all the plugs was measured using a combined NMR and gas porosimetry (CNG) method. Oil and water saturation were also obtained using an industry-standard method developed by the Gas Research Institute (GRI) on the rock material close to where the plug was drilled. The oil and water saturations measured on the preserved plugs using 2D T1-T2 NMR and CNG are consistent with those from the GRI method using crushed rocks and an invasive cleaning procedure. The results show that oil and water saturations were accurately determined from 2D T1-T2 NMR on preserved source rock samples with high confidence. The NMR method is nondestructive and noninvasive and takes less than 4 hours on a preserved source rock plug, while GRI is destructive and invasive and can take several weeks for an accurate measurement on one sample. The measured results can be further used to determine the production potential of a source rock well in combination with log data.

Oxidative Hydraulic Fracturing Fluid to Enhance Production from Source Rock Reservoirs

Summary The steep production declines generally observed after hydraulic fracturing in unconventional source rock reservoirs has been attributed to several potential causes. Recently, a new additive to the stimulation fluid system was proposed to extend economical longer-term production from these formations. Oxidizer-laden fracturing fluid systems are shown to create cracks and deep channels within the organic matter present in the source rock, such as kerogen, thereby increasing the source rock permeability and enhancing the hydraulic conductivity of the exposed fracture faces. To this end, the fluid design and recommendations for its application are illustrated herein. Oxidants composed of oxychlorine (ClOn−) and oxybromine (BrOn–) (where n = 0 to 4) are effective for kerogen depolymerization or degradation at depth. This study illustrates the beneficial effects of two specific oxidizers—sodium chlorite (NaClO2) and sodium bromate (NaBrO3)—on kerogen-rich source rock subjected to in-situ reservoir conditions. Source rock samples were cut and polished to test the oxidizer’s impact on the organic and inorganic regions. Scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS) were performed on the rock surface to identify specific organic matter features. The samples were then chemically treated with varying conditions of NaClO2 or NaBrO3 (concentration range: 0.013–0.054 M; temperature: 150°C; and time: 3–24 hours). Samples were returned to the scanning electron microscope for post-treatment analysis. Furthermore, the oxidants were packaged within a slickwater hydraulic fracturing fluid system for field application, and their effects on viscosity and friction reduction were also studied. SEM images and EDS maps of kerogen-rich rock samples observed before and after treatment with oxidizing fluid showed a series of cracks formed throughout the organic matter domains, where increasing the concentration of oxidizer in the treatment fluid showed a clear increase in the prevalence of cracks throughout the surface. The effect of time was also observed, as short treatment times resulted in porosity/permeability creation in the kerogen, though longer treatment times were associated with more severe degradation. Optimal conditions for NaClO2 and NaBrO3 concentrations in the additive fluid systems were different and will be herein highlighted. Each oxidizer (10–20 pptg concentration) was added to slickwater with variable friction reducer concentration (1 gpt, 2 gpt, and 4 gpt), and shear sweeps performed at both 70°F and 180°F. A negligible difference is observed between the viscosities of the base fluid and the fluid with either oxidant at low friction reducer concentration. Meanwhile, flow loop tests demonstrated that the oxidizer did not affect the friction reducer except to slightly boost the performance due to the salt effect on the polymer. Two strong oxidants, available as commodity chemicals, are shown to be effective in cracking kerogen and any present organic matter, thus creating permeable channels and enhancing the overall permeability of the exposed source rock fracture faces. Meanwhile, the proposed fracturing fluid additives display good compatibility with other slickwater fluid components, demonstrating the potential for universal usage in unconventional stimulations. The recommendations for its application as a fluid additive in slickwater are herein illustrated.

Coupling of source rock gas expulsion intensity and reservoir quality in time and space-a key to determine gas accumulation in Upper Paleozoic tight sandstones of the Mugua gas field, Ordos Basin, China

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

The effect of lamina and lithofacies assemblage on molecular maturity of oil in a shale source-rock reservoir

This paper discusses the effect of the source rock–reservoir assemblage and the assemblage–induced variability in hydrocarbon expulsion and the subsequent molecular composition as well as molecular thermal maturity within a hybrid shale system. The characterization work was conducted on lithofacies and microlamina scales using core samples from the Chang 73 sub-member of the Triassic Yanchang Formation in the Ordos Basin, China. Samples were collected from a narrow interval with a depth range of less than 15 m, and the main characterization work was performed by Rock-Eval pyrolysis and GC–MS analysis. The results show that chemical fractionation of preferential expulsion and migration of the saturated fraction exists in the source rock–reservoir assemblages at both the lithofacies and lamina scales. However, the molecular composition behaves differently at the lithofacies and lamina scale's source rock–reservoir assemblages, in which ∑C21−/∑C22+ is higher in lamina scale reservoir but lower in lithofacies scale reservoir. It is assumed that the low-molecular weight n-alkanes also follow molecular fractionation. The lithofacies reservoir has a lower ∑C21−/∑C22+ because of the strong storage capacity of the laminated micro-reservoir within shale, which prevents the newly generated lighter oil from being charged into the lithofacies reservoir. The variation trends of thermal maturity indices Ts/hopane, the relative pregnane content, and TA(I)/TA(I + II) ratios, which have the same chemical basis with ∑C21−/∑C22+, carry the same maturity signature as ∑C21−/∑C22+. The above profile of the molecular composition and molecular-derived thermal maturity parameters indicate that within the short interval of a shale system where no differences in thermal maturity are expected, chain scission reactions and their derived thermal maturity indicators are very sensitive to source rock and reservoir. In addition, within a shale system, oil is more easily to expel out from the organic-rich lithofacies that are interbedded with organic-lean lithofacies. Oil expulsion may promote both chain cracking of oil and subsequently kerogen decomposition. This may provide geological evidence to explain why the frequent-stacking assemblage of source rock and reservoir lithofacies in a hybrid shale system is an ideal target for shale oil exploration.

Saturation Height Modelling for Tight Sandstone Reservoirs with Gas Diffusion Dynamics Taken into Account

Interpreting and predicting the saturation of tight sandstone gas reservoirs are the key task to improve the reservoir development. The role of gas diffusion dynamics is stronger than that of buoyancy during the gas accumulation of tight sandstone reservoirs. In this study, a saturation height model that takes gas diffusion dynamics into account is proposed, which can complement logging saturation interpretation and provide a better practice in saturation prediction. Taking the study of the Sulige tight sandstone gas reservoir in China as an example, the saturation height model compares the controlling factors and uncertainties affecting the saturation distribution, characterizes the complex gas-water distribution, and determines the lower gas charging limits. This study concludes that the configuration between gas diffusion dynamics and reservoir capillary pressure controls the distribution of saturation. The buoyancy effect only serves to improve the saturation at regional uplifts with good petrophysical properties. The different saturation characteristics in the central, western, and eastern parts of the Sulige gas field are precisely caused by the different configurations of source rock quality and reservoir quality. This study provides a key reference for static model and development deployment.

Characterizing petroleum in source-rock core samples using HRGC data

Solvent extracts obtained from center-cut horizontal core plugs selected in the Upper Wolfcamp (UW) and Eagle Ford source-rock (SR) beds contain unaltered volatile (i.e., gasoline range) hydrocarbon (HC) compounds because they are extracted in a closed vial. Therefore, a C7 source parameter, a C7 maturity parameter, and pristane/phytane ratios are used to compare the source and thermal maturity of these petroleum and oil samples produced from nearby wells landed in the same SR reservoirs. Five distinct pay zones previously identified in the UW SR reservoir using geologic criteria each contain slightly different kinds of petroleum generated at different levels of thermal maturity. A thick overlying carbonate reservoir contains the kind of petroleum generated by the kerogen present in one underlying SR pay zone. The same source and maturity parameters demonstrate that the oil-prone kerogen present in the Eagle Ford SR beds in core plugs selected from wells located ≈7.5 mi (12 km) apart on the San Marcos Arch in South Texas formed in different depositional environments. It is difficult to allocate commingled oil samples using only core-plug extracts because solvents extract the producible oil plus a component that does not readily flow from SR reservoirs because it is sorbed in kerogen and/or on clay minerals. However, because only saturate HC compounds are used to determine the C7 source and maturity parameters, they provide valuable insights about the nature of the free oil present in SR reservoirs and commingled oil samples.

Scanning electron microscopic evaluation of broad ion beam milling effects to sedimentary organic matter: Sputter-induced artifacts or naturally occurring porosity?

Research examining organic-matter hosted porosity has significantly increased during the last decade due to greater focus on understanding hydrocarbon migration and storage in source-rock reservoirs, and technological advances in scanning electron microscopy (SEM) capabilities. The examination of nanometer-scale organic-matter hosted porosity by SEM requires the preparation of exceptionally flat geologic samples beyond the abilities of traditional mechanical polishing, which can deform or otherwise obscure organic surfaces. To meet this demand, broad ion beam (BIB) milling was introduced as a sample preparation technique for SEM petrographic analysis of geologic samples. As with any sample preparation technique, there can be unintended consequences. In this study, we examined the development of nanometer-scale sputter-induced voids caused by BIB milling of thermoset plastic binder material [poly(methyl methacrylate), PMMA] used for the mounting of geologic samples, and artifact sputter-induced voids in the organic matter of Green River Formation and Kimmeridge Clay Formation source rocks. Development of artifact sputter-induced voids was evaluated in relation to variations in the slope of the sample examination surface (0.0–4.9% slope), effectively varying the angle of ion incidence. The results indicate that only minor variations in the angle of ion incidence can generate sputter-induced voids in both PMMA (10.0–386.2 nm diameter sputter-induced voids) and sample sedimentary organic matter (solid bitumen; 12.2–103.6 nm diameter sputter-induced voids). Overall, average artifact pore diameters increased with increasing ion incidence angle within PMMA. Although sputter-induced voids within solid bitumen in the Green River Formation sample were only found in limited extent, the size of these void artifacts falls within the same size range as naturally occurring meso-macroporosity. That is, the pore-like artifacts could easily be misconstrued as naturally developed organic porosity, which is a major concern for SEM-based porosity evaluation methods. This study describes the factors that contribute to the creation of artifact sputter-induced voids, their distinguishing characteristics, and best practices for avoiding the creation of ion-induced artifacts.

Methane pore accessibility, densification, and accommodation by organic matter in the Niobrara Formation at wet-gas thermal maturity conditions

Petroleum within unconventional source-rock reservoirs is hosted in organic matter and mineral pore space as well as in voids and microfractures. Recent work has shown that for source-rock reservoirs in the dry gas window, significant portions of methane (CH4), the main component of petroleum at elevated maturities, can be stored within fine (<5 nm) organic matter porosity. However, within reservoirs at lower thermal maturities (e.g., peak oil or wet-gas conditions), the distribution and behavior of CH4 and the higher alkanes that comprise gas condensates across pore sizes is unclear, especially for pores with diameters <50 nm. Understanding CH4 distribution within these settings provides insight for petroleum generation, movement, and recoverability, enabling increased accuracy of estimated ultimate recovery. Here wide Q-range total neutron scattering was used to evaluate perdeuterated methane (CD4) behavior at reservoir pressures (200–750 bar) and temperature (60 °C) in a sample at the late oil/wet gas thermal maturity stage from the Late Cretaceous Niobrara Formation, an active petroleum producing formation within the Denver-Julesburg Basin, U.S.Neutron scattering data show that mesopores within the Niobrara Formation sample exhibit mass fractal scattering, similar to previously measured U.S. marine shale samples. In the presence of CD4, scattering intensities between Q = 0.02–0.1 Å−1 (corresponding to nominal pore diameters from 25 to 5 nm, respectively) decrease with increased pressure up to 750 bar where at least 80% of all pores with ∼25 nm diameters are CD4 accessible. In contrast, between Q = 0.1–1 Å−1 (corresponding to nominal pore diameters from 5 to 0.5 nm, respectively), scattering intensity initially increased at the lowest CD4 pressure tested (200 bar) before decreasing with increasing pressure. These signal fluctuations with CD4 pressure are interpreted to arise from the creation of pores with diameters <5 nm, likely through deformation of solid bitumen by supercritical CD4, and/or the incorporation of CD4 within sample organic matter. This new porosity represents an increase of at least 8% in available pore volume within the sample, although the majority of these pores do not persist following removal of CD4. Additionally, there is strong evidence for densification of CD4 within the sample indicated by a shift in the CD4 intermolecular scattering peak to higher Q-values compared to bulk CD4. These results provide insight into fluid properties within source-rock reservoirs at late oil/wet gas thermal maturities, especially as they relate to organic porosity interconnectivity, and are discussed with perspective toward pressure management of gas condensate wells.

A New Natural Gas Accumulation Model in the Triassic Xujiahe Formation: A Case Study in the Tongjiang-Malubei Area of the Sichuan Basin

The natural gas in the Triassic Xujiahe Formation (T3x) is reported to be mainly derived from the T3x source rock itself. Here, we report a new natural gas accumulation model, which demonstrates that the T3x gas in the Tongjiang-Malubei (TM) area is derived from both T3x and underline marine source rocks. The T3x gas in the TM area is characterized by CH4 with a gas dryness coefficient above 0.99, indicating a high thermal maturity. The δ13C values of the methane, ethane, and propane in the T3x gas in the TM area are −33.7~−29.2‰, −32.7~−28.3‰, and −32.8~−29.5‰, respectively. Compared with the T3x gas in the Yuanba area, which was sourced from the T3x source rock, the T3x gas in the TM area contains heavier δ13C in methane and lighter δ13C in ethane, showing a partial reversal carbon isotope distribution (δ13C1 &gt; δ13C2). According to their chemical and isotopic compositions, the T3x gas in the TM area was a mixture of coal-type and oil-type gases. The coal-type gas was mainly derived from the type III kerogen of the T3x source rock, and the oil-type gas was derived from the type-I kerogen of marine source rock in the Permian Wujiaping Formation (P3w). The oil-type gas migrated upward along the deep-seated faults that connect the P3w source rock and T3x sandstone reservoirs, and then mixed with coal-type gas in the T3x reservoirs, resulting in large-scale gas accumulation. This new gas accumulation model is controlled by a dual gas source supply and a high efficiency migration via the fault system. The findings of this study can help us to better understand the gas accumulation mechanism with the development of late-stage penetrating faults, which not only have implications for future petroleum exploration and development in the TM area, but also affect other analogous areas in the Sichuan Basin.

Petroleum geological features and hydrocarbon enrichment of Linhe Depression in Hetao Basin, NW China

Based on paleogeomorphology, drilling and seismic data, this paper systematically studies the structural and sedimentary evolution, source rock characteristics, reservoir characteristics and formation mechanism, hydrocarbon accumulation model and enrichment law in the Linhe Depression of the Hetao Basin, NW China. The Hetao Basin mainly experienced three stages of evolution, namely, weak extensional fault depression, strong extensional fault depression and strike-slip transformation, giving rise to four positive structural belts (Jilantai, Shabu, Nalinhu and Xinglong), which are favorable areas for oil and gas accumulation. The two main saline lacustrine source rocks, Lower Cretaceous Guyang Formation and Oligocene Linhe Formation, are characterized by high sulfur content, rich algae, early maturity, early expulsion, and wide oil generation window. The large structural transition belt in the intermountain area around the Hetao Basin controls the formation of large-scale braided river delta deposits, which are characterized by high quartz content (50%–76%), long-term shallow burial and weak compaction, low cement content, and good reservoir properties in delta front sandbody. The burial depth of the effective Paleogene reservoirs is predicted to reach 8000 m. Three hydrocarbon accumulation models, nose-uplift near sag, buried hill surrounding sag, fault nose near source rock, are constructed. The law of hydrocarbon accumulation in the Linhe Depression is finally clarified as follows: near-source around the depression is the foundation, high-quality thick reservoir is the premise, good tectonic setting and trap conditions are the key.

Characterising the economic Proterozoic Glyde Package of the greater McArthur Basin, northern Australia

The greater McArthur Basin is an informal term for a Palaeo-to-Mesoproterozoic sedimentary system that consists of terranes from the McArthur Basin, Birrindudu Basin, and the Tomkinson Province. These spatially distant basins are interpreted to connect in the subsurface based on geophysical, lithological, and geochronological evidence. The coeval sedimentary units of the greater McArthur Basin were subdivided into non-genetic depositional ‘packages’ bookended by regional unconformities. In ascending order, these packages are the: Redbank, Goyder, Glyde, Favenc, and Wilton Packages. The ca. 1660–1610 Ma Glyde Package is the focus of this study and includes the economically important Barney Creek Formation, found in the McArthur Basin sensu stricto. The Barney Creek Formation hosts the world-class, sediment-hosted, Zn-Pb-Ag McArthur River deposit. Importantly, it is also a key petroleum source rock and unconventional hydrocarbon reservoir, containing Australia’s geologically oldest oil and gas discoveries and forming a part of the McArthur Petroleum Supersystem. Consequently, identifying chronostratigraphically similar units elsewhere in the greater McArthur Basin is important for explorers in finding analogous economic resources.In situ Rb–Sr geochronological results of the Barney Creek Formation shales sourced from borehole LV09001 yielded ages of 1634 ± 59 Ma and 1635 ± 67 Ma. Shale samples from Fraynes Formation in borehole Manbulloo S1 were dated at 1630 ± 57 Ma and 1636 ± 42 Ma using the same approach. These ages are in good agreement with U–Pb ages of tuffaceous layers from the same units, suggesting that they represent their early burial histories and not secondary, post-depositional events. These results indicate that the Fraynes Formation and the Barney Creek Formation are direct chronostratigraphic equivalents, with ages within analytical error of each other.In addition to the geochronological similarities, the δ13Ccarb,87Sr/86Sr, and δ88/86Sr isotopic constraints from both units also display parallel geochemical fingerprints up-section. These include a positive δ13Ccarb excursion of ∼2.0 ‰, a trend towards more crustal-dominated 87Sr/86Sr ratios, and a negative δ88/86Sr excursion of ∼-0.25 ‰. These findings further support the application of isotopic chemostratigraphy as a powerful tool to correlate distal carbonaceous rocks in the basin system. Importantly, these geochemical fingerprints also show that the McArthur Group and the Limbunya Group experienced similar changes in palaeoenvironments during the evolution of the basin system. However, trace element data collated in this study indicates that they may have recorded different, heterogeneous palaeoredox histories. Geochemical models based on redox-sensitive trace elements V and Mo suggest that the Fraynes Formation sustained a much more euxinic water column as opposed to the Barney Creek Formation. These differences may have implications for the accumulation and preservation of base metals and hydrocarbons within the sediment.

Sedimentary features and sequence stratigraphy of the successions around the Carboniferous–Permian boundary in the Ordos Basin: links to glacial and volcanic impacts

The sedimentary successions around the Carboniferous–Permian boundary (CPB) in the Ordos Basin were investigated using extensive outcrop, borehole, well logging, thin section, and geochemistry data to study sedimentary and sequence stratigraphic responses to glaciation and volcanism in paleotropical transitional strata. Within the studied interval, five distinct lithofacies have been identified, including bauxite, coal, and carbonaceous shale (No. 8 + 9 coal seams), sandstone (Qiaotou), limestone (Baode), and mudstone, which can be classified into three lithofacies associations. The most complete lithofacies association is composed of bauxite, coal, carbonaceous shale, sandstone, limestone/mudstone or their combinations from the bottom to the top, while coal and carbonaceous shale, as well as sandstone, are absent locally, resulting in the formation of the other two types of lithofacies associations. The occurrence of bauxite indicates shelf exposure and weathering, the occurrence of coal and carbonaceous shale indicates swampiness of the shelf, and the occurrence of sandstone reveals river rejuvenation; all of these are thought to be sedimentary responses to the transcontinental glacier expansion in Gondwana around the CPB. The presence of limestone and mudstone indicates carbonate platform and lagoon deposition, respectively, in the context of the earliest Asselian transgression caused by volcanism-induced glacier melting. The lithofacies associations record the regressive–transgressive cycles that occurred because of glaciation and volcanism near the CPB. The top surface of bauxite can be used as a sequence boundary, while the lowstand systems tract consists of the No. 8 + 9 coal seams and the Qiaotou sandstone, and the transgressive systems tract consists of the overlying Baode limestone and laterally equivalent mudstone. The lowstand systems tract, which contains source rock and hydrocarbon reservoirs, and the overlying transgressive systems tract, which serves as cap rock, form an excellent source-reservoir-seal combination.

Control of oil and gas formation in the Shahejie Formation by the Li Xian Slope Fracture in the Jizhong Depression

Combining the information on the period of fault activity, hydrocarbon source rock distribution and reservoir distribution within the Lixian slope of the Jizhong Depression, the study was conducted on the controlling role of fractures on hydrocarbon formation. The results of the study show that: 1. the influence of fractures on the formation of traps, (1) the nose-like tectonic zone controls the formation of lithological traps of broken nose traps; (2) traps are formed at the segmentation point of the lower plate of the positive fault Gao Yang fault, which is located at the boundary of the external and external zones; (3) Fault activity controls the formation of trap closure; 2. The influence of fracture on oil and gas transportation, the role of oil and gas in the process of vertical transportation, combined with the location of hydrocarbon source rock development and the activity of the fault, fracture controls the vertical transportation of oil and gas.

Differential evolution of extracted bitumen and solid bitumen in a hybrid shale system

Organic solvent extracted bitumen (EB) and microscopically observed solid bitumen (SB) carry many geological implications in unconventional source-rock reservoirs. EB is a commonly used term in organic geochemistry, and SB is normally used in organic petrology. Although both EB and SB are secondary organic matter initially formed from kerogen degradation and partially describe the same components, they are defined by different physical and chemical criteria and have specific applications, and thus are rarely comparatively investigated. In this study, by taking the shale of the seventh member of the Upper Triassic Yanchang Formation in the Ordos Basin, China, as a case study, we performed an integrated characterization on the two types of bitumen. The characterization was carried out on source rocks and reservoir assemblages at two scales: lamina-scale (organic-rich lamina and silty lamina) and lithofacies-scale (shale and sandstone). Programmed temperature pyrolysis (Rock-Eval 7 pyrolysis), gas chromatography–mass spectrometry (GC–MS), and Raman spectroscopy were used in this study. The samples are distributed within a 12 m interval and therefore should have experienced the same degree of thermal stress. However, maturity parameters derived from GC–MS for EB and Raman spectroscopy for SB exhibit a different inferred thermal maturity between source rocks and reservoirs at both lithofacies- and lamina-scales. The side-chain scission reactions related (non-)biomarker parameters such as Ts/C30H, ΣnC21−/ΣnC22+ alkanes, relative C21 + C22 sterane content and TA(I)/TA(I + II) suggest higher thermal maturity in source rocks (shale and organic-rich lamina) than the corresponding reservoirs (sandstone and silty lamina), while Raman-derived parameters RBS and G-FWHM indicate higher maturity in reservoirs than the corresponding source rocks. It is speculated that the EB measured by GC–MS comprises saturated and aromatic components corresponding to relatively mobile hydrocarbons. The maturation of the source rock exerts greater control over this component than that of the reservoir. In comparison, the SB measured using Raman spectroscopy mainly consists of solid residue left behind after migration and/or decomposition of a once-liquid oil phase that is less readily able to move. It is more intensely altered by the organic–inorganic interactions (mineral dissolution–precipitation processes) in the reservoir than that in the source rock, resulting in a consolidated SB with higher aromaticity. The storage ability of silty lamina in shale may complicate the data interpretation of geochemical differences in EB- and SB-derived parameters. On a practical note, when assessing thermal maturity, taking into the account the lithology or rock texture, which affects the organic–inorganic interactions, as well as specific components detected by different techniques may provide helpful clues to explain some contradictory results.

The Controls of Laminae on Lacustrine Shale Oil Content in China: A Review from Generation, Retention, and Storage

The successful development of shale oil in China has claimed that laminated shale is a favorable lithofacies for the effective extraction of petroleum. Clarifying the role of laminae in shale oil generation, migration, storage, and enrichment is urgent and important. Starting from the describing and classifying of the lamina, the common methods and terms used to delineate lamina types are briefly summarized. The results of different schemes are often mutually inclusive, which prompted scholars to work towards a unified division scheme. The influencing factors of oil retention in shale systems, including organic matter (OM) type, total organic carbon (TOC) content, OM maturity, mineral composition, pore structure, and preservation conditions, are systematically discussed. Subsequently, comparative work on source rock quality, reservoir properties, and hydrocarbon expulsion efficiency of shales with different laminar structures is carried out. The comparison results of shale with different rock structures reveal that the laminated shale has a high expulsion efficiency. However, the strong oil generation capacity and superior storage space of laminated shale synergistically control the considerable amount of retained oil in the shale system. Especially the oil mobility of laminated shale is also considered because of great pore size and pore connectivity. The fine evaluation of laminar structure and prediction of laminar distribution has great significance for the selection of shale oil “sweet spot area” or “sweet spot interval”.

Sequence stratigraphy and reservoir characterization of the lower Eocene rocks (Thebes Formation) along the Tethyan Ocean's southern margin: biostratigraphy and petrophysical parameter applications

The Egyptian lower Eocene carbonate rocks (Thebes Formation) are part of an extensive carbonate platform formed during an eustatic regression along the Tethyan Ocean's southern margin. These rocks are essential in developing Egypt's petroleum system because they can operate as vertical seals in specific basins or as source-reservoir rocks. However, few in-depth studies have been conducted to explore the diagenetic history, pore system, petrophysical characteristics, and sequence stratigraphic framework of these rocks and its relationship to the global sequences. Multiple datasets (foraminiferal assemblages, petrographic, and petrophysical data) from the lower Eocene strata exposed in Wadi El-Dakhl and El-Sheikh Fadl sections on the western side of the Gulf of Suez were integrated. The biostratigraphic examination of the planktic foraminifera shows that three Eocene biozones (E5–E7) were identified in the studied successions. The reservoir quality index and the flow zone indicator show that reservoir quality ranges from poor to fair and good. The primary reservoir porosity was resulted from diagenetic processes, including dissolution, fracturing, and meteoric diagenesis, which enhanced reservoir quality. The inferred benthic foraminifera and petrographic studies indicate a shallowing upward trend and deposition in fluctuating settings ranging from upper slope to middle shelf. This progressive reduction in the relative sea level corresponds to a gradual eustatic decline and demonstrates the enhanced control of tectonic activity and eustasy. Consequently, the Thebes Formation was deposited due to Tethyan sea-level changes, and its pore system was influenced by tectonics associated with the Syrian Arc system and Gulf of Suez rifting.