Mature Source Rocks Research Articles

Petroleum systems in a buried stratovolcano: Maturation, migration and leakage

Buried volcanic systems are being increasingly studied due to their potential for hydrocarbon and geothermal exploration and subsurface storage of fluids such as CO2. Whilst widespread secondary porosity and fracturing increase reservoir potential in volcanic rocks and associated epiclastic deposits, these processes often also compromise seal integrity, leading to hydrocarbon leakage. Volcanism was widespread offshore northwestern New Zealand in the Miocene and petroleum has been discovered in the buried Kora stratovolcano. We analyse the petroleum system in this volcano using basin modelling to better understand controlling factors on the petroleum potential of buried volcanos. We reproduce charge of this accumulation from a marine source rock, the Waipawa Formation. In addition, there is significant potential for gas generation from Late Cretaceous coal measures of the Rakopi Formation. Modelling results are consistent with an effective fluid plumbing system and suggest that good quality connected reservoirs are present. In addition, Cretaceous faults that were reactivated in the Miocene act as migration pathways. However, models also suggest that significant amounts of petroleum have leaked during volcanic activity and related early maturation of source rocks. Models further predict that overburden and seal rock quality remain insufficient to support large petroleum accumulations. Low seal quality is consistent with the observation of high amplitude anomalies in reflection seismic data above the Kora volcano that are likely related to gas charged sediments and gas leakage. The occurrence of leakage is also consistent with extensive fracturing and oil shows in marine deposits overlying the volcano. These results highlight that the potential of buried volcanic systems to store petroleum and other fluids depends to a large extent on their structural evolution and burial history. On a global scale, hydrocarbon and greenhouse gas leakage of volcanos emplaced in petroliferous basins could have been significant in earth history with the potential to influence global climate.

Controlling Factors of Gas-Bearing Properties in Permian Tight Sandstone Based on Sealing Corings, Sulige Gas Field, Ordos Basin, Northern China

Gas saturation (Sg) is an important parameter for studying the gas-bearing properties of tight sandstone; however, there has been limited research on gas-bearing properties based on sealing coring. This study determines the controlling factors of the gas-bearing properties of tight sandstone in the Permian He8 Member of the Sulige Gas Field, Ordos Basin, Northern China, based on sealing coring, logging, drilling, gas testing, and laboratory analysis. The He8 Member Sg distribution is 17.9–63.8% (main range: 30–45%) and shows a downward trend from bottom to top. The Ro and hydrocarbon generation intensity of the source rock, reservoir porosity, and permeability tend to control the Sg in stages. When these parameters are less than 1.8%, 17 × 108 m3/km2, 10%, and 0.5 × 10–3 μm2, respectively, Sg increases significantly. When each parameter is greater than the aove boundary value, the change in Sg is not obvious. Four types of gas-bearing patterns of tight sandstone can be observed according to the distribution of reservoir and source rock conditions: “upper and lower constant,” “upper low–lower high,” “upper high–medium low–lower high,” and “upper high–lower low”; these patterns are mainly controlled by high maturity source rocks, reservoir physical properties, reservoir physical properties and structure, and structure, respectively. The corresponding gas test results reveal the existence of pure gas, pure gas and gas–water, gas–water, and gas-bearing water and pure water layers, respectively.

Controls on Early Miocene carbonate and siliciclastic deposition in eastern Java and south Makassar Straits, Indonesia

The Early Miocene stratigraphy of NE Java and the southern Makassar Straits is examined in the context of siliciclastic sediment supply and subsidence (creation of accommodation space), as indicated by biohermal carbonate growth. Stratigraphic variation is examined geographically and assessed quantitatively, using geohistory analysis. During the Oligocene through to basal Miocene times, basin development had been dominated by extension with local transtension. This changed within the Early Miocene to regional compression, increasing in magnitude with time. Three tectonic events, at about 24 Ma (base of section studied), at 21 Ma, and roughly 16 Ma are described in terms of the influence they had on stratigraphy. Most significant was the concentration of siliciclastics on the proximal side of the Oligo-Miocene axis of subsidence, which caused isostatic loading and nearby pinnacle reefs to achieve high relief, but ultimately an acceleration in siliciclastic input at about 16 Ma caused simultaneous reef extinction. Carbonates of Early Miocene age are important hydrocarbon reservoirs, and the siliciclastics are a geographically variable part of the overburden and seal, as well as causing the thermal maturation of hydrocarbon source rocks. The stratigraphic framework described here will have implications for facies and exploration risk prediction into under-explored regions around the study area. The tectono-stratigraphic framework is carefully constrained for age and facies inputs, and the resulting palaeogeographic history indicates a new model of basin development. This dynamic framework correlates to coeval tectonic processes over a large region and has important implications for Sundaland plate tectonics.

The potential of shale gas resources in Peninsular Malaysia

Even though the black shales in Peninsular Malaysia covered a quarter of the total surface area and have been overlooked for their economic potential except few workers have evaluated their thermal maturity using rock-eval pyrolysis, vitrinite reflectance analysis and illite crystallinity. According to these research works, the shales have been categorized into immature, mature and overmatured successions, which in turn dictated the exploration activities of commercially viable shale gas in the onshore Peninsular Malaysia. In this work, published and unpublished data on the scattered black shales of Peninsular Malaysia were examined to assess exploration potential of shales from various stratigraphic windows. Thus, using comparative evaluation of all the thermal history plots of the black shales from Peninsular Malaysia; areas of thermally matured source rocks are identified. According to the thermal maturation assessment; the Palaeozoic black shales in the Peninsular Malaysia have minimal generative potential for economically viable source rock for hydrocarbon, whereas the younger successions of Oligocene to Miocene have considerable potential to serve as source rocks of feasible prospect, provided permissible geological settings are met.

Controls on generation and accumulation of blended gases (CH4/H2/He) in the Neoproterozoic Amadeus Basin, Australia

Various gases are generated in the subsurface, by diagenetic processes, fluid/rock interactions, maturation of petroleum source rocks and microbial activity. Often these gases just leak at the surface but sometimes they may accumulate in a subsurface trap. The present study investigates the case of the southern part of the Amadeus Basin, Australia, where exploration wells tested a blend of hydrocarbon (HC), helium (He) and hydrogen (H2). In Mt Kitty-1 well, He- and H2-rich gases were reported (He ∼9%, H2 ∼11.4%) with traces of HC, whereas C1 and C2+ HC gases associated with He were discovered in Magee-1 well. Seismic and well data elucidate accumulation of the gas blend within a classical subsurface system with a structural trap, a permeable reservoir and a thick salt layer as seal. This salt, the Proterozoic Upper Gillen, is overlying the Heavitree sandstones and fractured basement reservoirs. The former is dominated by intergranular porosity (∼13%), whereas the latter is commonly associated with complex patterns of fractures associated with deep-seated faults. The sources of blended gases are different: thermal cracking of organic matter for hydrocarbons, radiolytic decay of radioelements for helium. Radiolysis, and water reduction as well as oxidation of hydrocarbons are open hypothesizes for H2 generation in the study region. Neoproterozoic and Early Paleozoic tectonic episodes (e.g. Petermann; Alice Springs) allowed the formation of various structural traps where the gas blend was accumulated.The large quantity of He, light gas slowly generated by the crustal radioactivity indicates that the seal is very efficient and that accumulations could have been in place for millions of years very likely with an evolving CH4/H2/He ratios through time. The presence of gas chimneys and surface depressions in the basin indicate that the generation, and/or migration of the gases are still active. All the data are consistent with a long-term accumulation of this gas blend, different from the short term H2 retention in the reservoir that was proposed in other contexts such as in Mali.

The occurrence of a palaeo‐lithification front in an overpressured basin (Chalk Group)—Timing from clumped isotopes and seismic stratigraphic analysis

AbstractThis study proposes a unique workflow to unravel complex burial diagenetic histories of overpressured basins based on the integration of seismic and well log data, biostratigraphy, petrography, clumped isotope analyses and basin modelling. This approach is demonstrated with an example from the Chalk Group in the Danish Central Graben, where a seismic‐scale palaeo‐lithification front has been observed and studied in detail to elucidate the timing of the establishment of overpressured conditions and its relation to changing diagenetic activity. The palaeo‐lithification front separates high‐porosity chalks above, that dominantly underwent mechanical compaction and contact cementation, from low‐porosity chalk below, that dominantly underwent severe pressure dissolution and pore‐filling cementation. Analysis of chalk buried under hydrostatic conditions shows a strikingly similar lithification front between 1000 and 1200 m burial, much shallower than the lithification front in the Danish Central Graben at a current depth between 2100 and 2400 m below seafloor. The discrepancy of 1200 m is due to the establishment of overpressured conditions that limited the increase in effective stress as burial continued, finally halting burial compaction when formation fluids started to carry the lithostatic weight. Basin modelling data indicate that this occurred at the end of the Oligocene for large parts of the Danish Central Graben, which is much earlier than the Middle Miocene timing that is currently assumed. The results imply a regional occurrence of a relict lithification front in the North Sea Basin, its position guided by stratigraphy, but mainly dependent on the maximum effective stress experienced during its burial history. The study shows that the porosity bipartition is a remnant of the past and not from ongoing compaction as has previously been suggested. Since it was established before the thermal maturity of the main source rocks, chalk below the lithification front must have formed a sealing unit during hydrocarbon migration. The recognition of the lithification front is also of importance to velocity modelling and depth‐conversion since a non‐linear increase between velocity and depth is expected across this boundary. The methodology may be applied in other overpressured basins where the diagenetic state of reservoir rocks at the end of hydrostatic conditions must be constrained.

Down under and under Cover—The Tectonic and Thermal History of the Cooper and Central Eromanga Basins (Central Eastern Australia)

The Cooper subregion within the central Eromanga Basin is the Swiss army knife among Australia’s sedimentary basins. In addition to important oil and gas resources, it hosts abundant coal bed methane, important groundwater resources, features suitable conditions for enhanced geothermal systems, and is a potential site for carbon capture and storage. However, after seven decades of exploration, various uncertainties remain concerning its tectonic and thermal evolution. In this study, the public-domain 3D model of the Cooper and Eromanga stacked sedimentary basins was modified by integrating the latest structural and stratigraphic data, then used to perform numerical basin modelling and subsidence history analysis for a better comprehension of their complex geologic history. Calibrated 1D/3D numerical models provide the grounds for heat flow, temperature, thermal maturity, and sediment thickness maps. According to calibrated vitrinite reflectance profiles, a major hydrothermal/magmatic event at about 100 Ma with associated basal heat flow up to 150 mW/m2 caused source rock maturation and petroleum generation and probably overprinted most of the previous hydrothermal events in the study area. This event correlates with sedimentation rates up to 200 m/Ma and was apparently accompanied by extensive crustal shear. Structural style and depocentre migration analysis suggest that the Carboniferous–Triassic Cooper Basin initially has been a lazy-s shaped triplex pull-apart basin controlled by the Cooper Basin Master Fault before being inverted into a piggy-back basin and then blanketed by the Jurassic–Cretaceous Eromanga Basin. The interpreted Central Eromanga Shear Zone governed the tectonic evolution from the Triassic until today. It repeatedly induced NNW-SSE directed deformation along the western edge of the Thomson Orogen and is characterized by present-day seismicity and distinct neotectonic features. We hypothesize that throughout the basin evolution, alternating tectonic stress caused frequent thermal weakening of the crust and facilitated the establishment of the Cooper Hot Spot, which recently increased again its activity below the Nappamerri Trough.

Pressure variations in the northern part of the Danish Central Graben, North Sea

The overpressure variation in the Cenozoic–Jurassic succession in the northern part of the Danish Central Graben may broadly be divided into three major compartments. An upper hydrostatically pressured unit comprises the post-mid Miocene–recent succession down to c . 1200 m depth in the northern and c . 700 m in the southern parts of the Danish Central Graben. The second compartment comprises the mid-Miocene smectite-rich clays down to and including the upper Cretaceous chalk. There the Paleogene–Lower Miocene succession provides the seal. The third compartment constitutes the Jurassic succession with pressure above hydrostatic that may exceed twice that seen at the upper Chalk level. Pressure levels can be estimated using the Eaton approach for the second compartment that are in agreement with pressure data. Modelling of the transient pressure development in the Cretaceous–mid-Miocene succession broadly complies with the Eaton estimates and shows that the main overpressure build-up has occurred within the last 10 myr. The overpressure in this succession may be mapped using methods that exploit correlations between fluid pressure and the degree of consolidation, while that in the Jurassic cannot. However, the lateral variation in the Upper Jurassic overpressure correlates broadly with the maturity of the Upper Jurassic source rock, allowing the pressure variation to be mapped. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure

Numerical 3D modeling of burial and temperature history, source rock maturity, and hydrocarbon generation in the onshore northeastern Netherlands

Numerical 3D basin modeling is used to reconstruct the burial and temperature histories in onshore northeastern Netherlands, incorporating the four main geological structural elements Groningen Platform, Lauwerszee Trough, Friesland Platform, and Lower Saxony Basin. The structural framework is based on recently published open access depth surface data; public temperature and vitrinite reflectance data from 28 wells are used to evaluate burial and temperature histories. Four modeled burial histories and the maturity evolution of the structural elements are presented. The hydrocarbon generation in major source rock intervals in the Carboniferous, Jurassic, and Cretaceous is simulated using recently published kinetic and literature data. Modeling results indicate highest present-day temperatures and maturities of the Paleozoic sedimentary succession in the Lauwerszee Trough and the Lower Saxony Basin, where the deepest burial occurred. Two major phases of deep burial and subsequent uplift occurred in Carboniferous to Permian times and from the Triassic to the Jurassic. Both intervals strongly influenced the maturation and transformation of kerogen from Paleozoic source rocks. The highest modeled maturities of the Mesozoic groups are observed in depressions between salt diapirs in the Lower Saxony Basin. Out of the two major source rock intervals within the Mesozoic, the Cretaceous Wealden Shale generated hydrocarbons from Late Cretaceous times.

Relationship between the tectono-thermal events and sandstone-type uranium mineralization in the southwestern Ordos Basin, Northern China: Insights from apatite and zircon fission track analyses

Tectonic evolution significantly influenced the sandstone-type uranium mineralization in the continental basins of northern China. To better understand the relationship between the tectono-thermal evolution and uranium-ore-forming process, we selected the southwestern Ordos Basin as the research subject. Detrital apatite and zircon fission track analyses of samples from the Early Cretaceous succession were conducted in this work. The results revealed five stages of tectono-thermal events since the Late Mesozoic: (i) the Late Jurassic–Early Cretaceous (165 ∼ 140 Ma), (ii) the late Early Cretaceous (130 ∼ 100 Ma), (iii) the Late Cretaceous (100 ∼ 60 Ma), (iv) the Late Paleogene–Early Neogene (55 ∼ 20 Ma), and (v) the Late Miocene–present (<10 Ma). These activities are recognized as the results of the multiplate convergence of the Siberian, paleo-Pacific, and Indian plates since the Mesozoic. Furthermore, the Late Jurassic–Early Cretaceous uplifting of the western Ordos Basin supplied the abundant sedimentation materials and uranium materials for the Early Cretaceous succession in the basin, which acted as excellent ore-bearing layers. The regional extension in the Early Cretaceous has led to an increasing geothermal gradient, which caused the maturity of hydrocarbon source rocks and escape of oil and gas. The following tectonic revisions supplied the pathways and favorable locations for oil and gas accumulation and uranium mineralization. The latest activity has driven the reactivation and re-enrichment of the uranium mineralization since the Late Miocene.

On the determination of oil charge history and the practical application of molecular maturity markers

Determining the thermal maturity and the charge history of crude oil to any reservoir, has key implications for understanding petroleum generation, accumulation history and hence identification of exploration potential. In this paper we combine studies of several source rock sequences and associated crude oils using quantitative component concentration data in addition to traditional molecular marker ratio parameter approaches. The case history studies include examination of organic-rich sapropelic marine source rocks from the Second White Speckled Shale Formation (2 WS Fm.), in the Western Canada Sedimentary Basin and the upper Jurassic Draupne Fm. in the North Sea and their related oils. Each molecular component in the petroleum has a unique concentration evolution curve during source rock maturation, in which n-alkanes, light aromatic hydrocarbons and diamondoid hydrocarbons increase in concentration with increasing maturity, while biomarkers decrease in concentration with maturity. This maturity dependent concentration variation plus the ubiquitous mixing of multiple oils in the reservoir is a key process that complicates the direct application of qualitative molecular marker ratio approaches to analysis of petroleum systems. We suggest an alternative maturity assessment approach using maturation calibrated curves of absolute concentrations of biomarkers and other alkanes in petroleum, coupled with selected aromatic hydrocarbon ratios to track the maturity/petroleum mass fraction relationships for a reservoired oil mixture in a more complex but realistic manner. Isoprenoid alkanes show less variation in concentration with maturity than other components and may be used as an internal reference point for mass fraction maturity and charge history assessment. Using component concentration data normalized to the concentration of the isoprenoid alkanes and calibrated using source rock analyses at different maturity levels from a single petroleum system (2WS), a simple mass balance model was constructed that allowed aggregate concentration data to be calculated for any mixture of oils produced in a prescribed oil charge history. In principle any charge history can be simulated using this approach and comparing the modelled and actual quantitative compositional profiles of crude oils allows differentiation of the more plausible and implausible oil charge histories for that particular reservoir. Clearly considerable refinement of this approach is needed but it appears that such a procedure has the potential, if developed further, to be a useful addition to the arsenal of petroleum geochemists and basin modelers. Knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, enables the estimation of missing charge in the basin, allows the detection of complex multi-history charge scenarios, and provides a much more robust and complete data set for calibration of basin model charge history assessments. It also, with further development may be integrated into stochastic basin modelling approaches to study petroleum systems.

Anabar–Lena Composite Tectono-Sedimentary Element, northern East Siberia

Abstract The Anabar–Lena Composite Tectono-Sedimentary Element (AL CTSE) is located in northern East Siberia extending for c. 700 km along the Laptev Sea coast between the Khatanga Bay and Lena River delta. The AL CTSE consists of rocks from the Mesoproterozoic to Late Cretaceous in age with the total thickness reaching 14 km. It evolved through the following tectonic settings: (1) Meso-Early Neoproterozoic intracratonic basin; (2) Ediacaran–Early Devonian passive margin; (3) Middle Devonian–Early Carboniferous rift; (4) late Early Carboniferous–latest Jurassic passive margin; (5) Permian foreland basin; (6) Triassic to Jurassic continental platform basin; and (7) latest Jurassic–earliest Late Cretaceous foreland basin. Proterozoic and lower–middle Paleozoic successions are composed mainly of carbonate rocks, while siliciclastic rocks dominate upper Paleozoic and Mesozoic sections. Several petroleum systems are assumed in the AL CTSE. Permian source rocks and Triassic sandstone reservoirs are the most important play elements. The presence of several mature source rock units and abundant oil and gas shows (both in wells and in outcrops), including the giant Olenek Bitumen Field, suggests that further exploration in this area may result in economic discoveries.

Prospect evaluation based on integrated petroleum system analysis: Block E case study, south-eastern edge of Precaspian Basin (Kazakhstan)

Generative potential and thermal maturity for Upper Palaeozoic source rocks from the south-eastern edge of Precaspian Basin were determined using Rock–Eval. A high hydrocarbon source rock generative potential and high degree of thermal maturity for the Lower Permian, Mid-Carboniferous strata have been revealed based on 39 rock samples. TOC values of 0.4–5.5% have been obtained for mature source rocks. Integrated geochemical analysis determined from Rock–Eval studies combined with 1D basin modelling was utilized in order to reconstruct thermal evolution for the Upper Palaeozoic source rocks. Calibrated 1D models for three wells had been constructed to understand petroleum system. For two deep exploration wells (Nur-1 and Tassym SE-1), which penetrated pre-salt strata at the depths of 5.7 and 7 km, respectively, the impact of salt diapirism on timing of maturation was modelled. Type II kerogen was used, which is based on previous palaeogeographic studies. The stratigraphic framework and major stages of geodynamic evolution were analysed. Salt-related structural traps in post-salt strata have been described based on 3D seismic data, and additional intra-salt sediment packages have been delineated. Discovered producing oil fields in the Upper Triassic and Jurassic–Cretaceous stratigraphic sections are mainly confined to the four-way dip structural closures above the steep flanks of salt structures. Based on burial and thermal modelling, the maturation and generation behaviour of kerogen Type II below salt-related minibasins and close to thick salt diapirs were inferred. For Lower Permian SR with type II kerogen, the generation peak (maturity over 50%) occurs in Middle to Late Jurassic. For predominantly carbonate and terrigenous-carbonate Mid-Carboniferous marine SR, generation peak occurs earlier below salt withdrawal minibasins. Implications for deeper hydrocarbon prospectivity were made for the study area, and methodology for evaluating hydrocarbon potential adopting 1D basin modelling technique and geochemical data is presented.

Geochemical Characteristics and Genesis of Cambrian Shale Gas in the Southern Margin of Hannan Ancient Uplift

The geological characteristics of shale and the gas composition and carbon isotopic variation from the shale are very important indicators for the shale gas study. This article analyzed the geological characteristics of Cambrian Niutitang shale and focused on the gas composition and carbon isotopic characteristics of the shale gas from the Cambrian Niutitang Formation. We can see that the total organic carbon content ranges from 0.41 to 4.29%, with an average of 1.65%, which is mainly type I and Ⅱ1. The thermal maturity of sample ranges from 1.98 to 2.53%, with an average of 2.30%, which is in the postmature stage of thermal evolution. The Cambrian Niutitang Formation shale gas in the southern margin of the Hannan ancient uplift is the high-quality hydrocarbon gas methane that takes an absolute majority with a content ranging from 89.60 to 99.19% with an average of 96.46%. The wetness of the gas from the study area ranges from 0.06 to 0.42%, with only 0.25% on an average, which is defined as typical dry gas. The distribution of carbon isotope values has partial “reverse” characteristics that are δ13C1 &amp;gt; δ13C2 and δ13C2 &amp;lt; δ13C3. The natural gas of Niutitang Formation in the study area belongs to thermogenic gas. At the same time, it is found that some data points are beyond the range of thermogenic gas, which is mainly due to the low-humidity and heavy carbon isotope value of methane caused by the high maturity of source rock. In the study area, the Niutitang Formation natural gas carbon isotope values are located in Zone III with the characteristics of mixed reversal gas in the δ13C1-δ13C2 part.

Thermal stability and parameter validity of hopane series in mature shales – A case study from Dongying Depression, eastern China

Molecular compositions extracted from source rocks offer direct indicator of the organic matter input, depositional redox conditions and thermal maturity levels that source rock has experienced, however, the application of such technique commonly encounters difficulty in highly mature system. A suite of twenty-eight organic-rich lacustrine shale samples from the Eocene Shahejie Formation in the Dongying Depression, East China were geochemically investigated, aiming to obtain a comprehensive thermal stability sequence of hopanes and the validity of various molecular parameters. By means of systematic comparisons on compound ratios and concentrations, the thermal stability of hopanes is presented as follows: [C35 hopane (H) < (C33H, C32H) < C34H < C30H < C31H < C29H < 17α(H)-22,29,30-trisnorhopane (Tm) < 18α (H)-30-norneohopane (C29Ts) < C30 diahopane (D) < 18α(H)-22,29,30-trisnorneohopane (Ts), from the least stable to the most stable]. Limited validity of the paleoenvironment and organic matter input parameters such as C35H/C34H and C31 22R/C30H ratios in mature source rocks is caused by the preferential decomposition of C35H and C30H compounds during thermal maturation. Therefore, application of molecular parameters derived from hopanes need to be exercised with extra caution. Their validity varies with maturity levels and most hopane related parameters will lose their effectiveness at peak oil generation stage. Meanwhile, a novel maturity parameter (Ts/C29Ts ratio) derived from thermal stability difference of hopanes was proposed herein, supported by strong correlations with vitrinite reflectance and other two reliable maturity parameters. Upon further calibration, this novel maturity parameter can be deemed as a reliably alternative indicator and is expected to have wide application in highly mature source-rock/oil maturity assessment, especially for the shale oil system. The findings of this study may help for better understanding of limited validities of molecular indicators during thermal evolution.

The Occurrence of Bedding-Parallel Fibrous Calcite Veins in Permian Siliciclastic and Carbonate Rocks in Central Thailand

Bedding-parallel fibrous calcite veins crop out at two Permian carbonate localities in the Phetchabun area, central Thailand, within the Nam Duk and Khao Khwang Formations. Samples are studied to determine their petrographic, geochemical and isotopic character, depositional and diagenetic associations and controls on the formation of fibrous calcite across the region. Biomarker and non-biomarker parameters are used to interpret organic matter sources in the vein-hosting units, the depositional environment and levels of source rock maturation in order to evaluate source rock potential in the two Formations. Carbon and oxygen isotope values of the veins and the host are determined to discuss the source of carbonates and diagenetic conditions. The petroleum assessment from the Khao Khwang and Nam Duk Formations suggests that both Formations are a petroleum potential source rock with type II/III kerogen deposited in an estuarine environment or a shallow marine environment and a slope-to-basin marine environment or an open marine environment, respectively. The bedding-parallel fibrous calcite veins from the Khao Khwang and Nam Duk Formations are divided into two types: 1) beef and, 2) cone-in-cone veins. The carbon and oxygen isotope compositions from the fibrous calcite veins suggest that the calcite veins could be precipitated from a carbon source generated in the microbial methanogenic zone. The results in this study provide a better understanding of the interrelationship between the bedding-parallel fibrous calcite veins and petroleum source rock potential.

Diamondoids and thiadiamondoids generated from hydrothermal pyrolysis of crude oil and TSR experiments

Diamondoid compounds are widely used to reflect thermal maturation of high mature source rocks or oils and oil cracking extents. However, diamondoids and thiadiamondoids were demonstrated to have newly been generated and decomposed in our hydrothermal pyrolysis of crude oil and TSR experiments. Our results show that adamantanes and diamantanes are generated primarily within the maturity range 0.48–2.1% and 1.2–3.0% EasyRo, respectively. Their formation is enhanced and the decomposition of diamantanes obviously lags at elevated temperatures compared with anhydrous experiments. MDI, EAI, DMAI-1, DMDI-2 may serve as reliable maturity proxies at > ca.1.0% EasyRo, and other isomerization indices (TMAI-1, TMAI-2 and DMAI-2) are effective for the highly mature organic matter at EasyRo > 2.0%. The extent of oil cracking (EOC) calculated from the broadly used (3- + 4-) MD method (Dahl et al. in Nature 399:54–56, 1999) is proven to overestimate, especially for highly cracked samples due to the new generation of (3- + 4-) MD. Still, it can be corrected using a new formula at < 3.0% EasyRo. Other diamondoid-related indices (e.g., EAI, DMDI-2, As/Ds, MAs/MDs, DMAs/DMDs, and DMAs/MDs) can also be used to estimate EOC. However, these indices cannot be applied to TSR-altered petroleum. TSR is experimentally confirmed to generate diamantanes and thiaadmantanes at 1.81% EasyRo likely via direct reactions of reduced S species with hydrocarbons and accelerate the decomposition of diamantanes at > 2.62% EasyRo compared with thermal chemical alteration (TCA). More studies are needed to assess specific mechanisms for the formation of thiadiamondoids under natural conditions.

Hydrocarbon accumulation characteristics in the inter-salt shale oil reservoir in the Eocene Qianjiang Depression, Hubei Province, China

Research on the migration and accumulation of hydrocarbons in shale oil reservoirs composed solely of organic-rich mudstones has not received adequate attention. The Qianjiang Formation provides an opportunity for research on the hydrocarbon accumulation mechanism due to the presence of hydrocarbon migration characteristics in its inter-salt organic-rich fine-grained rocks. In this study, the inter-salt stratum of the tenth rhythmite can be classified into three sections: lower, middle, and upper. The middle section is mostly composed of laminated marlstones and laminated calcite-bearing argillaceous dolomicrites, whereas, the lower and upper sections mostly contain bedded muddy dolomicrites and glauberite. Geochemical analysis was conducted to study the organic matter enrichment mechanism and shale oil accumulation characteristics. The results indicate that the middle section has the highest organic matter abundance, with poor organic matter abundance displayed by the other sections. The C27/C29 sterane and extended tricyclic terpane ratios suggest that the organic matter types in different sections of the inter-salt stratum differ, and the middle section has more aquatic organic matter than other sections. The sedimentary structures and salinity-related parameters indicate that the middle section was developed in a deep stratified saline lake and that the other sections were formed in a shallow hypersaline lake. This study shows that high biological productivity and stratified lake water facilitated the enrichment of organic matter, resulting in high organic matter content in the middle section. The oil saturation index and hydrocarbon composition suggest that hydrocarbons were differentially accumulated in the inter-salt stratum of the tenth rhythmite. The maturity-related biomarkers further revealed the possible migration paths of hydrocarbons in the inter-salt stratum. Based on the aforementioned analyses, this study established an inter-salt shale oil accumulation model. This study suggests that hydrocarbons were released from the mature source rocks in the deep depression with differential migration laterally and vertically within the inter-salt stratum. The study of the Qianjiang Depression shows that organic-rich fine-grained rocks cannot only form in situ sweet spots but may also possess migrated hydrocarbons inside them, which are characterized by high organic matter abundance and oil saturation. This research provides a new case for further understanding hydrocarbon accumulation inside source rocks.

Evaluation of Thermal Maturation of Hydrocarbon Potential Source Rocks From Kombe-Kompina-Missole Areas of the Douala Sub- Basin Using Spore Color Variation Technique

The Douala sub-Basin is well-known as a highly prospective basin for petroleum generation. The depletion of some oil Wells originally discovered in Cameroon calls for further investigation on the maturity of potential source rocks so as to discover more oil fields. The current methods used by many researchers for evaluating the thermal maturity of potential source rocks are mostly the geochemical techniques which are pretty expensive. Thus, this study was set out to evaluate thermal maturation of potential source rocks exposed in the Kombe-Kompina-Missole areas of the Douala Sub-Basin through the use of spore color variation as an alternative cheaper method of determination with a higher precision than the former. This work had three specific objectives; to carry out loggings, to obtain and identify sporomorphs, to determine the extent of thermal alteration of sporomorphs present in the samples through microscopic examination of spore and pollen color variation. A total number of fifteen samples obtained from the sedimentary sequences encountered in the studied area were sent for laboratory analysis. The results obtained from palynological analysis showed that color index of organic matter at Kombe and Kompina ranges from 2 to 2/3 which are immature to early mature source rocks with kerogen type II, III and IV. While for Missole, color index ranges from 2/3 to 3 indicating early maturity to mature source rocks with kerogen type II. Facies identified from lithofacies analysis included: sandstones, shales, mudstones, siltstones, conglomerates. Therefore, palynological methods based on spore color variationis an efficient and cheaper method of determining thermal maturity.

Calculation and controlled factors of hydrocarbon expulsion efficiency using corrected pyrolysis parameters: A Songliao case study

In recent years, rock pyrolysis parameters combined with a mass balance method have been used to calculate the hydrocarbon expulsion efficiency. However, due to the experimental procedure of rock pyrolysis, the residual hydrocarbon amount (S1) is underestimated, and the hydrocarbon-generation potential of kerogen (S2) is overestimated, so that the hydrocarbon expulsion efficiency calculated from the pyrolysis parameters before correction is higher than the actual value. In this paper, the pyrolysis parameters were corrected by performing pyrolysis before and after the extraction of source rocks, and the hydrocarbon expulsion efficiency of the mudstone of the Qing 1 member of the Ha14 well in Songliao basin was calculated using the chemical kinetics method. The hydrocarbon expulsion efficiencies before and after the correction were considerably different, the hydrocarbon expulsion efficiency of the Ha14 well after correction was 17.5% lower than that before correction. The study show that the higher the abundance and maturity of source rock are, the higher the hydrocarbon expulsion efficiency is; the oil-type organic matter has a higher hydrocarbon-expulsion efficiency than the gas-type organic matter; the interbedded sand and mud type source-reservoir configuration relationship is beneficial to hydrocarbon expulsion; the underwater diversion channel phase has the highest hydrocarbon expulsion efficiency.