Kerogen Transformation Research Articles

Effect of Temperature on Kerogen Transformation and Hydrocarbon Generation in Bazhenov Formation (Western Siberia, Russia) Rocks During Hydrous Pyrolysis

The aim of this investigation is to determine the role of temperature in hydrocarbon generation in Bazhenov formation source rocks, as hydrothermal processes in situ are supposed to be the main contributor to kerogen transformation in Western Siberia. Laboratory modeling of organic matter isothermal transformation in powdered and extracted samples by hydrous pyrolysis at 300 °C, 325 °C, 350 °C, 375 °C, and 400 °C for 24 h was performed. Heated samples were analyzed via pyrolysis, and hydrocarbons were investigated by GC and GC-MS. Results show that more than 90% of the kerogen generation potential was utilized. The amounts of liquid and gaseous products reached 82 and 126 mg of hydrocarbon/g TOC, respectively. The volume of generated gas increased while the maximum production of liquid decreased with temperatures over 350 °C. The biomarker composition of liquid products at different temperatures was similar. The characteristics of kerogen and the product composition had a high correlation with the parameters for samples naturally formed in situ under an elevated heat flow. More subtle chemical analyses are required to determine the effects of kerogen’s chemical structure and the rock mineral composition on oil and gas generation.

Hydrocarbon generation in the onshore and offshore of the Austral and Malvinas basins based on 3D petroleum system modelling

The Austral and Malvinas basins are prolific oil and gas provinces, estimated to contain a significant proportion of undiscovered hydrocarbon reserves in the South Atlantic. A three-dimensional basin and petroleum system model (3D BPSM) is presented to visualize the complex deformation history which impacted in the volumes of generated hydrocarbons from the Lower Cretaceous source rock (LC-SR) in fold-and-thrust belt (FTB) regions through geological time. Organic geochemistry and maceral analysis obtained from samples from 28 wells were incorporated to 3D BPSM to evaluate the source rock potential from the Austral to Malvinas basins. The LC-SR contains a type II to type II–III kerogen with most samples showing a regular to good (>1%), and in few cases, excellent (>4%) TOC contents in both basins. Modelling results show higher source rock maturities (dry gas window) and kerogen transformation that occurred towards the fold-and-thrust belt regions, where deeper burial conditions were reached. A general decrease of maturity is observed towards the foreland regions of both basins. From Late Cretaceous large volumes of hydrocarbons were generated and expelled in fold and thrust belt regions of Austral and Malvinas basins. The main phase of hydrocarbon generation occurred during the Eocene, when the LC-SR reached the maximum burial, especially in the Fuegian-FTB. Hydrocarbon generation and expulsion continue to the present, particularly in the kitchen located in the eastern sector of the Malvinas Basin.

Effect of thermal maturation and organic matter content on oil shale fracturing

The Pabdeh Formation represents organic matter enrichment in some oil fields, which can be considered a source rock. This study is based on the Rock–Eval, Iatroscan, and electron microscopy imaging results before and after heating the samples. We discovered this immature shale that undergoes burial and diagenesis, in which organic matter is converted into hydrocarbons. Primary migration is the process that transports hydrocarbons in the source rock. We investigated this phenomenon by developing a model that simulates hydrocarbon generation and fluid pressure during kerogen-to-hydrocarbon conversion. Microfractures initially formed at the tip/edge of kerogen and were filled with hydrocarbons, but as catagenesis progressed, the pressure caused by the volume increase of kerogen decreased due to hydrocarbon release. The transformation of solid kerogen into low-density bitumen/oil increased the pressure, leading to the development of damage zones in the source rock. The Pabdeh Formation’s small porethroats hindered effective expulsion, causing an increase in pore fluid pressure inside the initial microfractures. The stress accumulated due to hydrocarbon production, reaching the rock’s fracture strength, further contributed to damage zone development. During the expansion process, microfractures preferentially grew in low-strength pathways such as lithology changes, laminae boundaries, and pre-existing microfractures. When the porous pressure created by each kerogen overlapped, individual microfractures interconnected, forming a network of microfractures within the source rock. This research sheds light on the complex interplay between temperature, hydrocarbon generation, and the development of expulsion fractures in the Pabdeh Formation, providing valuable insights for understanding and optimizing hydrocarbon extraction in similar geological settings.

Geochemical characterization and paleo-burial history modelling of unconventional resources: A case study from the Kimmeridge Clay Formation (KCF) in the UK North Sea

For several decades the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Upper Jurassic to Lower Cretaceous Kimmeridge Clay Formation (KCF). In this study, we have combined the analysis of total organic carbon/pyrolysis and vitrinite reflectance geochemical data from KCF samples with 1D basin modelling to investigate the potential for shale oil and gas plays in the Outer Moray Firth region. The results of geochemical evaluation show that most of the samples have very good to excellent hydrocarbon generation potential and contain predominantly oil-prone Type-II kerogen. A few samples show a significant oil saturation index above 100 mgHC/gTOC, which indicate a good potential for producible shale oil. The modelling results suggest that vitrinite reflectance values for the KCF vary mainly between 0.51 and 1.15%Ro, with kerogen transformation of up to 86 %. This is indicative of early-oil to late-oil/early-gas maturity window at present day, and within the range reported for proven shale oil plays. The KCF shows good oil saturation in most of the modelled well locations of up to 6.4 mg/g rock, indicating potentially producible shale oil. Predictions from modelling support the interpretations from geochemical data.

ROLE OF ELECTROMAGNETIC FIELDS IN DEVELOPMENT OF OIL AND GAS GENERATION PROCESSES IN UNCONVENTIONAL RESERVOIR ROCKS

The specifics of the Bazhenov Formation sediments, which are fundamentally different from traditional Green River oil shales, is that the processes of organic matter (kerogen) transformation into hydrocarbons have not yet been completed in them. The achieved paleotemperatures allowed the studied sediments to enter the main phase of oil formation during the regional catagenetic transformation of kerogen, but they failed to realize their oil-maternal potential to the full extent. At present, there are several unsolved problems for these rocks, related both to the genesis of oil and to the search for commercial hydrocarbon deposits in them and the development of technologies for their further development. The processes of «proto-oil» formation in the Bazhenov Formation sediments are still poorly understood. In fact, these processes are a system of equations with many unknowns, the correct solution of which is still impossible at the current stage of study. In our opinion, an important role in the development of oil formation processes in the Earth’s subsurface is played by magnetic fields formed under the action of a number of reasons (in particular, during the development of numerous tectonic disturbances). Our laboratory experiments by gas chromatography showed that in bitumoids of the studied samples there is a progressive shift of the «naphthenic hump» associated with internal transformations in the magnetic field. As a result of these studies, a decrease in the naphthenic fraction of hydrocarbons in samples heated in a magnetic field was recorded compared to samples without exposure to a magnetic field. Significant differences were found in paired samples of most geochemical characteristics - n-C23/24, n-C25/26, n-C26/27, n-C29/30, OEP, CPI, naphthene sum. Taking into account the influence of electromagnetic fields on the development of oil and gas generation processes allows us to create a completely new technology of «maturation» of hydrocarbon compounds (proto-oil) directly in the oil-maternal sediments and the formation of «artificial/technogenic» oil deposits.

Kerogen structure and porosity in Woodford Shale before and after hydrous closed-system pyrolysis

Micro-plugs of the Upper Devonian to Lower Mississippian Woodford Shale from the Ardmore Basin in southern Oklahoma were analyzed before and after hydrous pyrolysis (300, 320, 330, and 340 °C for 24 h) by using a combination of μ-FTIR, CP-Py-GC/MS, BIB-SEM-EDS techniques to investigate kerogen transformation and evolution of pore space.Tasmanites and Leiosphaeridia in Woodford Shale are abundant macerals characterized by relatively long, unbranched alkyl chains, with an additional carboxyl component, and a minor contribution of aromatic structures based on μ-FTIR spectra results. The aliphatic νasCH2/ νasCH3 ratios show almost no correlation with pyrolysis temperatures, except for a minor increase of the ratio for both samples after pyrolysis at 330 °C, which may be attributed to cracking of C-C bonds next to a tertiary carbon atom. A decreasing aliphaticity and increasing aromaticity for alginite with increasing pyrolysis temperature and thus thermal maturity is indicated by the reduction of aliphatic CHx stretching bands and increasing γCH/ νCHx ratios. The relative abundance of olefinic bonding (νC=C) decreases in alginite compared to aromatic hydrogen (γCH) with higher pyrolysis temperature, and thus formation of monoaromatic rings is indicated by the condensation ratios (γCH/ νC=C); similar observations have been made on natural maturation series.This is in line with the CP-Py-GC/MS results on whole kerogen showing an increase of aromatic structures over aliphatic pyrolysis products with increasing thermal maturities, though with some differences between the two samples investigated. The differences are probably related to higher alginite/bituminite ratios in one of the samples, which also contain more N-compounds. In contrast, the other sample enriched in bituminite contains more S-compounds. Both FTIR spectra and EDS results document a loss of carbonyl/carboxyl C=O functional groups and/or O content with thermal maturation. The hydrocarbon generation potential parameter “A-Factor” (νCHx/ νCHx + νC=C), analyzed on alginite in this study, is rather consistent at different pyrolysis temperatures with a value of about 0.9 and with a slight tendency of higher values at higher pyrolysis temperatures.SEM observations show that there is no significant occurrence of microfractures in the initial samples and after pyrolysis at 300 °C, while microcracks and organic pores formed pore networks when pyrolysis temperature increased from 320 °C to 340 °C. Most of the newly generated cracks are parallel to the bedding. Mineral-filled Tasmanites cysts in Woodford Shale are silica-rich and may be related to the dissolution of siliceous tests (e.g., radiolarians).

Early porosity generation in organic-sulfur-rich mudstones

High total organic sulfur (TOS) content (i.e., Type IIS kerogen) is well known to significantly influence kerogen transformation but the effect of TOS content on the evolution of organic porosity has only rarely and indirectly been investigated. This study demonstrates that organic porosity is generated at lower thermal maturity in mudstones containing Type IIS kerogen relative to those with Type II kerogen. To our knowledge this phenomenon has not been previously demonstrated. The implications are relevant for the characterization of organic-rich mudstones as cap rocks, hydrocarbon reservoirs, and disposal reservoirs for CO2 or nuclear waste because pore systems control storage volumes and matrix fluid flow. Five thermally immature core samples were selected from three organic-rich mudstone units with low to high TOS content: the late Devonian Duvernay Formation (Canada), middle late Miocene Onnagawa Formation (Japan), and early Jurassic Gordondale member of the Fernie Formation (Canada). Hydrous pyrolysis was used to artificially mature splits of the immature samples to four maturity stages, upon which petrophysical and organic geochemical properties were measured and compared to baseline immature samples. Most porosity growth in Type IIS samples occurred below 0.70% VRoeqv, but in Type II samples was broader and robust until 1.1% VRoeqv.

Fluid inclusions geochemical characteristics as indicators of the organic matter transformation degree in Jurassic sediments of the Em-Ega crest (Krasnoleninsky arch, Western Siberia)

Fluid inclusions in quartz crystals from the Abalak formation carbonate rocks of 5 wells on the Em-Egovskaya summit of the Krasnoleninsky arch (Western Siberia) were investigated. Two-phase fluid inclusions with water-salt solutions, inclusions containing organic liquid, and single-phase gas fluid inclusions were found. For fluid inclusions with two-phases, the values of the homogenization temperature were obtained. For single-phase inclusions, the temperature of the second phase forming was revealed. It was established that two types of primary inclusions are present in one well, with oil and with water-salt solution. The homogenization temperature of the primary fluid inclusion containing a water-salt solution is 267°C, the homogenization of the oil-containing inclusion exceeds 300°C. In primary-secondary inclusions, the homogenization temperature reached 136 °C. Studies of the composition of inclusions by infrared spectrometry have shown that in single-phase inclusions, the gas is represented by methane. In primary-secondary inclusions, the composition may vary, while in the gas phase, the predominant components may be hydrocarbons with two or more carbon atoms. Studies of organic matter from the deposits of the Tutleim source-rock formation overlying the Abalak formation have shown that the stage of catagenetic transformation of kerogen in the studied wells changes. It was found that in wells in which organic matter is most transformed, the homogenization temperature of fluid inclusions exceeds 130°C. Thus, it is proved that on the territory of the Em-Egovskaya summit of the Krasnoleninsky arch, Jurassic deposits were effected by heat flows created by high-temperature fluids. Not only rocks of the Abalak formation were exposed by thermal processes, but also organic matter from the Tutleim formation was changed, as a result its maturity increased and the generation of hydrocarbon compounds was stimulated. The results obtained explain the difference in the catagenetic transformation of the organic matter of the Tutleim formation in this area. The study of the molecular composition of inclusions will allow us to more accurately reconstruct the conditions of hydrothermal processes. The study of fluid inclusions makes it possible to develop new criteria for the search for oil and gas deposits.

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.

Assessment of the thermal maturation, organofacies, and petroleum generation history of Sirte Shale Formation in Sirt Basin, Libya

The current study is conducted to investigate the upper Cretaceous (Campanian) Sirte shale Formation to better understand the regional abundance of the organofacies, thermal maturation levels, and the petroleum generation and expulsion histories during the geological time in one of the most important petroliferous basins in North Africa (Sirt Basin). Rock-Eval pyrolysis analysis of 988 samples in 56 wells that penetrated the Cretaceous section in the Sirt Basin was used to screen and study the geological and geochemical characteristics of the Sirte shale Formation. Multi-dimensional basin modeling, including 1D burial histories and 2D modeling approaches, was calibrated with %VRo and pyrolysis Tmax data to establish refined regional maturity of the Sirte shale Formation. By using the Rock-Eval data, the type, occurrence, and distribution of organofacies in time and space were investigated using analytical assessment procedures and present-day mapping, such as total organic carbon (%TOCp), hydrogen index (HIp), and kerogen transformation ratio (TRp) to define the lateral and vertical special variation. Key biological marker (biomarkers) data is used to determine their special types, abundance, and host sedimentary environments. We used integrated geochemistry with basin modeling to define the Sirte shale petroleum generation and expulsion history, petroleum phase-type and quantity, and expulsion efficiency. Results indicate that the current maturation levels in the general range of 0.4–1.35 %VRo (equivalent to 405 °C–460 °C pyrolysis Tmax) that found to allow Sirte shale Formation to enter transformation levels ranging from 20% to 91%, which is equivalent to 1,615 m–3,627 m burial depth. Sirte shale Formation is dominated by two types of organofacies (B and D/E), which are characterized by %TOC up to 5% and hydrogen index from 400 to 700 mg HC/g TOC with sudden lateral and vertical variation due to the influence of the marine and transitional – terrestrial sedimentary environments. Similar indications from the biomarker data were Pr/Py ratio shows a significant existence of anoxic and dysoxic environments (generally, 0.4–2.4). Alga marine (dominant), mixed, and minor terrestrial organic matter was defined to dominate the Sirte shale Formation as indicated by Pr/nc-17 and Py-nc18 data. The petroleum generation history of the Sirte shale Formation occurred in the Oligocene time (∼30 Ma). The higher expulsion efficiency for the oil phase, up to 84% detected in the deeper parts of the basin, and lower gas expulsion efficiency with its maximum up to 63%. During the geological time, two primary petroleum phases were generated and expelled (oil and gas) from the Sirte shale. The bulk fluid properties generated from Sirte Shale Formation indicate that range of GOR from 400 to 2000 scf/bbl and API in the range of 30–60.

Palaeoclimatic and diagenetic controls based on clay mineralogy and organic matter distribution: The continental rift Cuyo Basin (Triassic), west‐central Argentina

AbstractThe Triassic Cuyo rift Basin is one of the renowned petroleum systems in South America that records distinctive alluvial, lacustrine and fluvial settings with volcanic input. The present study focuses on the clay mineral assemblages that represent the syn‐rift to post‐rift fills. Four clay mineral assemblages are defined based on X‐ray diffraction, optical and electron microscopy analyses. The illite/mica‐dominated assemblage is documented in the syn‐rift I (Cerro de las Cabras Formation). Such mineral phases are inherited and derived from the erosion of pre‐rift units, suggesting that physical weathering associated with a warm and semi‐arid climate played a leading role in their occurrence. Authigenic smectite clays are diagnostic in organic‐lean mudstones of the syn‐rift II (lower Potrerillos Formation) which point to alteration of pyroclastic material under a warm and semi‐arid to humid climate. A warm and humid climate prevailed during the deposition of lacustrine hydrocarbon source rocks (upper Potrerillos and Cacheuta formations). Organic‐rich mudstones show the illite/mica–kaolinite–smectite assemblage in conjunction with amorphous organic matter and restricted terrigenous elements. Diagenetic kaolinite booklets and bipyramidal quartz are attributed to the acidification of pore‐water related to kerogen transformation during burial diagenesis. Vitrinite reflectance values (ca 0.63%) confirm that organic‐rich sediments reached the earliest oil window; however, smectite is devoid of illite layers throughout the Triassic succession, probably related to the absence of potassium in the system and the high crystallinity of the smectite, which delayed the transformation of smectite into mixed layers illite–smectite. Red mudstones of the post‐rift II (the fluvial‐lacustrine Rio Blanco Formation) show the kaolinite‐dominated assemblage where the authigenic kaolinite is interpreted to be derived from the alteration of volcaniclastic detritus and indicative of warm climate with markedly wet periods.

Postdiagenetic Changes in Kerogen Properties and Type by Bacterial Oxidation and Dehydrogenation

A significant part of organic carbon found on the earth is deposited as fossil organic matter in the lithosphere. The most important reservoir of carbon is shale rocks enriched with organic matter in the form of kerogen created during diagenesis. The purpose of this study was to analyze whether the bacterial communities currently inhabiting the shale rocks have had any impact on the properties and type of kerogen. We used the shale rock located on the Fore-Sudetic Monocline, which is characterized by oil-prone kerogen type II. We were able to show that shale rock inhabited by bacterial communities are characterized by oxidized and dehydrated kerogen type III (gas-prone) and type IV (nonproductive, residual, and hydrogen-free). Bacterial communities inhabiting shale rock were dominated by heterotrophs of the Proteobacteria, Firmicutes, and Actinobacteria phyla. Additionally, we detected a number of protein sequences in the metaproteomes of bacterial communities matched with enzymes involved in the oxidative metabolism of aliphatic and aromatic hydrocarbons, which may potentially contribute to the postdiagenetic oxidation and dehydrogenation of kerogen. The kerogen transformation contributes to the mobilization of fossil carbon in the form of extractable bitumen dominated by oxidized organic compounds.

DEVELOPMENT OF FIBROUS CALCITE VEINS RELATED TO HYDROCARBON GENERATION AND OVERPRESSURING IN ORGANIC‐RICH SHALE SOURCE ROCKS: THE VACA MUERTA FORMATION, NEUQUÉN BASIN, ARGENTINA

Fibrous calcite bed‐parallel veins (BPVs) are a typical feature of the Upper Jurassic – Lower Cretaceous Vaca Muerta Formation in the subsurface of the Neuquén Basin (Argentina). The formation is considered to be the main source rock in the basin as well as an important unconventional play. This study examines the growth of BPVs through an analysis of core from three wells located along a transect extending for some 150 km from the NE Platform near the basin margin in the east to the Agrio fold‐and‐thrust belt at the Andean deformation front in the west. The main objective is to integrate fluid inclusion data with the palaeothermal and palaeopresure evolution obtained from a regional‐scale 2D basin and petroleum systems model to examine the timing of fracture development and its relationship with hydrocarbon generation in the Vaca Muerta Formation through time.The apertures of BPVs were measured in more than 360 m of core from three wells (wells A, D and E). This data was combined with optical petrography to investigate the number of calcite cementation events, and the temperature of cement precipitation based on fluid inclusion data. The organic geochemical and mineralogical characteristics of the Vaca Muerta source rock were also analysed. The integrated results were incorporated into a poro‐elastic basin model to investigate the impact of horizontal shortening due to Andean compression on pore pressure development and fracturing in the Vaca Muerta Formation. This framework allowed the timing of BPV formation to be determined together with possible mechanisms governing overpressure conditions through time.Near the Andean deformation front in the west of the modelled section where the Vaca Muerta Formation is in the wet gas window (well D) and dry gas window (well A), BPVs are characterized by two or more generations of calcite fibres indicating multiple growth phases. Calcite which precipitated during cementation event 1 (E1) in the internal zones of BPVs consists of crystals oriented perpendicular to fracture walls, indicating perpendicular vein opening. Calcite precipitated during cementation event 2 (E2) in the outer zones of BPVs includes curved and oblique crystals. During this phase, shear occurred between the opening vein walls as a result of horizontal shortening. Cementation event 3 (E3) is characterized by an equant mosaic of calcite crystals which preserve intracrystalline porosity. E1cements formed between 110 and 90 Ma with trapping temperatures of ∼112 °C (upper Vaca Muerta, well A) and ∼125 °C (lower Vaca Muerta, well D). Fracturing resulted from disequilibrium compaction and from volumetric expansion due to primary cracking of kerogen within the oil window. E2 cements record a trapping temperature of ∼159 °C and formed between 70 and 55 Ma (lower Vaca Muerta, well D) during maximum burial of the Vaca Muerta Formation, synchronous with the secondary cracking of retained liquid hydrocarbons and the beginning of Andean compression. E3 cements (upper Vaca Muerta, well A) have a trapping temperature of ∼162 °C, and formed between 65 Ma and 53 Ma synchronous with the generation of thermogenic gas.By contrast, in the east of the modelled section in the less deformed foreland area of the Neuquén Basin where the Vaca Muerta Formation is in the early oil window (well E), BPVs are composed of a single generation of calcite fibres (E1)with a trapping temperature of ∼118 °C. The E1 cement is characterized by calcite crystals which are oriented perpendicular to fracture walls with no evidence of shearing. According to model simulations, cementation here occurred between 64 Ma and 53 Ma during maximum burial and was related to overpressures which resulted from both disequilibrium compaction and primary transformation of kerogen into oil.The data presented suggests that in some intervals of the Vaca Muerta Formation, a slight increase in TOC content is accompanied by an increase in vein thickness, with the highest number of cementation events occurring towards the Andean deformation front in the west of the study area compared to the foreland in the east.

Silurian hot shale occurrence and distribution, organofacies, thermal maturation, and petroleum generation in Ghadames Basin, North Africa

The Silurian hot shale in one of the African superglobal petroliferous sedimentary basins (Ghadames) were studied to provide new regional insights regarding the organofacies type, occurrence and distribution, thermal maturation levels, and the timing of petroleum generation and expulsion. Based on regional integrated geochemical data such as Rock-Eval and Leco TOC, the evaluation of hot shale organofacies was carried out to characterize the type, occurrence and distribution and to obtain present-day regional maps of total organic carbon content (%TOCpd), hydrogen index (HIpd) and kerogen transformation (TRpd). The hot shale thermal maturation levels were obtained using pyrolysis Rock-Eval Tmax, equivalent vitrinite reflectance (%VRo), and one, two and three-dimensional calibrated basin modeling approaches. Results show that the hot shale was entirely dominated by typical marine organofacies type B (kerogen type I/II) with %TOC ranging from 2% to 17.5%, and hydrogen index ranged from 50 to 750 mg HC/g TOC with apparent systematic trends throughout the basin margins, and depocenter for both %TOC and HI. The hot shale thermal maturation study indicates a general maturation range from early to the post-mature stages with 0.45–2.45 %VRo and 380 °C–510 °C as pyrolysis temperature range. The one and two-dimensional kerogen transformation study based on the obtained refined thermal model shows a general range from 20% to 98% transformation levels with a systematic increase from the basin margins toward the basin depocenter. The hot shale oil window (top and bottom) is defined to be in the range of 1,400 m–4,000 m burial depth, while the dry gas window of the hot shale is presented at a burial range of 4,000 m–5200 m. Such an observation and current geological and geochemical conditions rank the hot to be an attractive potential sweet spot area as an unconventional shale oil/gas play target in Ghadames Basin for future exploration activity in western Libya, eastern Algeria, and southern Tunisia.

Source rock properties and kerogen decomposition kinetics of Eocene shales from petroliferous Barmer basin, western Rajasthan, India

Hydrocarbon exploration and production are going on in Barmer basin (Rajasthan, India) for more than a decade. The potential source rocks are of Paleocene – Eocene age, and Mesozoic siltstones form the reservoirs. The western and central portions of the Rajasthan basin are characterised by extensive lignite formations, which can be promising for artificial transformation to oil and gas. We study the source rock properties, depositional environments and hydrocarbon generation potential of the Paleogene lignitic shales of the Giral lignite mine and the Cretaceous Sarnu siltstones for their source and reservoir rock potentiality. The total organic carbon content (TOC) of the Giral samples range between 0.76 and 49.83 wt% and the thermal maturity, as reflected by the pyrolysis Tmax, lies between 412 and 468 °C. Sarnoo siltstones, on the other hand, have a very low TOC ranging from 0.02 to 0.08 wt% and a Tmax of 320–608 °C. The higher TOC and a lower oxygen index (OI) of Giral lignites and shaly lignites indicate the prevalence of a reducing depositional environment. Bulk organic geochemical parameters involving kerogen pyrolysis and thermal degradation kinetics indicate a more promising hydrocarbon generation potential in the lignite than shales, which, however exhibits higher thermal maturity of organic matter. Giral lignites as well as shales show dominantly Type-III heterogeneous kerogen, which is sourced from terrestrial organic matter. This is also corroborated by a broader distribution of activation energy derived from the thermal decomposition of the kerogen. The kerogen transformation ratio (KTR) and the hydrocarbon generation rate (HGR) suggest a considerably earlier and quicker kerogen transformation. Samples from the Sarnoo area offer no significant information on the source rock characteristics, due to their lean organic nature. However, lignites and shaly lignites of the Giral mine are identified as excellent candidates for their suitability towards easy conversion into hydrocarbon products through artificial techniques.

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.

Stress distribution around kerogen particles as a measure of the initiation of bitumen-filled microfractures in organic-rich source rocks

In this article, we present a method used to model the initiation of bitumen-filled microfractures in immature, organic-rich source rocks. The first part presents the method used to calculate the stress distribution around the kerogen particles. The second part explains the method used to calculate the pressure change as a function of the transformation ratio and the resulting overpressure.•The effective principal stresses acting on the kerogen boundary were calculated.•Kerogen geometries were determined using the measured aspect ratio of the kerogen traces obtained from the petrography observation.•To estimate overpressure, the increase in pressure due to the transformation of kerogen to bitumen was calculated.

Organic pore heterogeneity and its formation mechanisms: Insights from the Lower Cretaceous lacustrine Shahezi shale in the Songliao Basin, NE China

Pores associated with organic matter are well known to play a significant role in shale gas capacities. However, an extremely high heterogeneity of organic pores often impacts our evaluation of reservoir quality. In this work, we analyze the formation mechanisms of the heterogeneity based on positioning observation method using a combination of field emission scanning electron microscopy and optical microscopy. These analyses were conducted on six lacustrine shale samples at the gas window in the Lower Cretaceous Shahezi shale, which is located in the Changling Fault Depression of Songliao Basin. The results reveal that organic pore heterogeneity is mainly attributed to four controlling factors. (a) One is different hydrocarbon generation potentials among different macerals. The degree of pore development from high to low is solid bitumen, vitrinite, and inertinite. The content of carbon by the weight percentage of solid bitumen, vitrinite, and inertinite is in the opposite order, which reflects that the different hydrocarbon generation potential of each maceral is the dominant factor. (b) Another one is the remnants of primary pores in organic matter with plant cell structures. Well preserved telinite, fusinite, and semi-fusinite show cell structures, and the cells that are not completely compressed or not fully filled retain the original residual pores. (c) The third one is evolutional differences of individual solid bitumen. Not all solid bitumen developed organic pores, which is mainly attributed to the difference of solid bitumen reflectance in different solid bitumen particles. The solid bitumen reflectance of porous solid bitumen is mostly distributed between 1.6% and 2.0%, in which oil cracking to gas is dominant and porous residual solid bitumen subsequently forms. The solid bitumen reflectance of non-porous solid bitumen peaks in 1.2–1.6%, which is in the stage of kerogen transformation and oil generation with rare pore development. (d) The last one is the catalysis of clay minerals. All organoclay complexes develop abundant sponge-like pores due to catalysis during the transformation from smectite to illite. A high content of illite in the mixed layers I/S increases the specific catalytic activities, promoting the organic matter and solid bitumen to further generate hydrocarbon and form pores. Most organic–inorganic mixtures develop pores also because of catalysis from inorganic minerals.

Evaluating transformation of marine kerogens from Rock-Eval measurements: A. Derivation of a scaled thermal maturation path from laboratory maturation data

Identification of kerogen type in source rocks and quantification of its transformation to hydrocarbon products upon thermal maturation are vital for petroleum exploration. These elements can be evaluated using the open pyrolysis of the Rock-Eval. Despite the importance of sulfur-rich marine kerogens (Type II-S) in petroleum systems, the maturation path of only Types I, II and III kerogens were characterized by the Rock-Eval parameters, and a comparison of the maturation path (defined as the HI-Tmax relation) for Type II and II-S is needed.A comparison of the HI-Tmax relation between Type II and II-S kerogens is presented here by compiling literature data of laboratory thermal maturation for six well-known source rocks. The source rocks include the Toarcian Shale, Kimmeridge, Barnett and Woodford for Type II and the Ghareb and Monterey for Type II-S. When comparing the HI-Tmax relation among the different source rocks, the extent of kerogen transformation cannot be readily evaluated because of variations in the immature properties of kerogens. This variation is overcome by normalizing the HI and scaling the Tmax of mature samples to their immature values. These operations create a new thermal maturation scale defined here as HIrelative-ΔTmax. While the suggested scale minimizes the impact of the heterogeneity within each kerogen type, it generates two distinctive maturation paths for each of them. Although Type II-S kerogens have a lower Tmax at the onset of maturation, the maturation path needed for full transformation is longer than that for Type II kerogens. The two maturation paths are statistically analyzed to generate an empirical law for each of them. Thus, the extent of marine kerogen transformation can be estimated using the empirical law and the suggested HIrelative-ΔTmax thermal maturation scale. The longer maturation path of Type II-S is hypothesized to result from enhanced thermal stabilization of the residual kerogen, driven by the rearrangement of sulfur moieties.