Generation Of Liquid Hydrocarbons Research Articles

Geochemical Properties and Gas-Bearing Analysis of Lower Cambrian Black Shale in Western Hunan Province

Western Hunan province and its surrounding areas are significant targets for shale gas exploration and development in southern China, where the black shale of the lower Cambrian Niutitang Formation and Wunitang Formation is extensively distributed. Geochemical analysis was conducted on the lower Cambrian black shale from a new exploration well of XAD1 located at the southeast margin of the Yangtze paraplatform, followed by a discussion on gas-bearing properties using molecular dynamics simulation. The geochemical characteristics indicate that the black shale in well XAD1 was primarily deposited in a strongly reducing marine environment, with organic matter predominantly composed of type I kerogen derived from algae. Currently, it has reached a stage of high to over maturity with limited potential for liquid hydrocarbon generation. The recovery of the original hydrocarbon generation potential shows that they are excellent source rocks and have completed the main hydrocarbon generation evolution. Despite the favorable conditions for shale gas formation observed in well XAD1, the low measured gas content within the Niutitang Formation suggests that other geological factors may have contributed to a substantial loss of shale gas. Gas adsorption simulation reveals that the maximum methane adsorption capacity (15.77 m3/t) was achieved by Niutitang shale during the late Silurian period when there was an abundant source of natural gas without any influence from CO2, H2O or other molecules. However, due to a lack of natural gas replenishment and subsequent tectonic uplift and subsidence causing variations in temperature and pressure, the methane adsorption capacity gradually decreased (to 6.56 m3/t). Furthermore, water occurrence within the shale reservoir further reduced the methane adsorption capacity (below 2 m3/t), while tectonic activities exacerbated the loss of shale gas potential within this study area. The findings indicate that the dynamic alteration of gas-bearing properties in shale reservoirs due to tectonic movements is a crucial factor influencing the success rate of shale gas exploration in the study area, provided that there are sufficient gas resources and superior reservoir conditions.

Depositional environments and source rock potential of some Upper Palaeozoic (Devonian) coals on Bjørnøya, Western Barents shelf

Upper Palaeozoic strata are potential sources for hydrocarbon plays on the Norwegian Barents Shelf. The island of Bjørnøya (Bear Island) is located on the western margin of the Barents Shelf and represents an exposed part of the Stappen High, which makes it an excellent location to investigate the source rock potential of this succession. Here, we investigate the organic geochemical composition and source rock potential of coals and organic-rich mudstones of Late Devonian to middle Permian ages. The thermal maturity of the analysed samples ranges from mature to overmature with some samples being in the late oil generation window, and thus exhibiting higher maturities than age and facies equivalent strata in central Spitsbergen in the NW corner of the Barents Shelf and on the Finnmark Platform to the south. The high maturities and thermal cracking may thus have negatively affected the applied isoprenoid and biomarker-based source facies parameters, which potentially inhibit correct source facies interpretation. However, our results and comparisons with previous studies indicate that the vitrinite- and inertinite-dominated humic coals occurring in the lower part of the succession formed by the accumulation of peat in fluvially-influenced, humid wetlands at paleo-equatorial latitudes during a pronounced episode of rifting in the Late Devonian (Famennian) to earliest Carboniferous (Mississippian). Our source rock evaluation indicates a good potential for liquid hydrocarbon generation for the coals of the Upper Devonian Røedvika Formation prior to maturation. The oil-prone organic matter of these coals is primarily considered as terrestrial and non-aqueous. Because of renewed rifting in the middle Carboniferous combined with a shift to arid climatic conditions, as well as an environmental change from dominantly terrestrial and marginal marine clastic to marine carbonate platform environments, the accumulation of wetland peats effectively came to an end. Thus, the overlying Carboniferous and Permian strata generally seems to yield poor to no hydrocarbon generation potential.

A tale of two vein types: Bed-parallel fibrous versus blocky filled fractures in organic-rich shales and their overpressured hydrocarbon fluids

Bed-parallel fractures are a common feature of organic-rich shales, and are generally interpreted as records of fluid overpressures due to hydrocarbon generation. However, the textural features of such cemented fractures differ widely, and the relationships between these textures and the vein-forming (fracturing and filling) processes—and, critically, their respective roles in accumulation and migration of hydrocarbons—remain uncertain. Here, we compare the physical conditions and opening mode of bed-parallel cemented fractures that show either fibrous texture indicative of antitaxial growth that kept pace with fracture dilation (commonly referred to as “beef”), or blocky texture indicative of unimpeded syntaxial crystallization into an open, fluid-filled space. Specifically, we analyzed formation conditions of bed-parallel fibrous filled fractures in the Shahejie (Eocene) shales, Bohai Bay Basin, east China, and the bed-parallel blocky filled fractures in the Wufeng-Longmaxi (Ordovician-Silurian) shales, Sichuan Basin, southwest China, to evaluate root causes for the different textures of these cements and discuss their roles in self-sourced hydrocarbon accumulation. We report that fluid inclusions in each filling type show distinct and systematic differences in the magnitude of fluid overpressure during different hydrocarbon generation stages of catagenesis. The formation of bed-parallel fibrous filled fractures, including the initial hydraulic fracturing and subsequent crystallization, occurred during the main stage of liquid hydrocarbon generation (i.e., the oil window) when lithostatic fluid pressures were achieved only sporadically and modest overpressures less than lithostatic usually prevailed. The initial bed-parallel fracturing of blocky fillings, in contrast, occurred during the main gas generation stage (i.e., the gas window), and subsequent blocky crystals precipitated after this stage during uplift after the maximum burial. In this case, super-lithostatic overpressures of the CH4-saturated fluids persisted essentially continuously and actively expanded the fractures at rates that were not met by the crystallizing cements.Such a model for blocky crystallization in an open horizontal space supported by super-lithostatic fluid pressures in petroliferous systems in sedimentary basins, is analogous to some systems in metamorphic rocks including even orogenic gold deposits, and some magmatic settings, especially related to S-type granites where they form greisens and tin-tungsten deposits by blocky filling of wolframite and quartz, and I-type granitoids where coarse muscovite veins occur for example in the deep roots of porphyry copper systems, as well as numerous pegmatites. Some elements that each of these settings share with the shale-hosted, bed-parallel blocky filled fractures, include that they involve in situ fluid production (by metamorphic devolatilization or magmatic degassing) and fluid escape is stifled by low background permeability such that fluid overpressures can build up, at least periodically, to match or exceed the lithostatic load. As a result of these divergent bed-parallel fracture filling processes, the fibrous textures record conditions of modest permeability that favored accumulation of nascent liquid oil, whereas the blocky fracture cements represent open fractures that contributed to permeability and expulsion of gas. We conclude that the fibrous filled fractures record an opening mode that was beneficial for shale oil enrichment, whereas dilation of blocky filled fractures provides important conduits for hydrocarbon expulsion and release of shale gas.

Paleodepositional environment and hydrocarbon generation potential of the Paleogene lignite in the Barmer Basin, Rajasthan, India

The Barmer Basin in Rajasthan is considered one of the most important petroliferous sedimentary basins of India. Apart from a hydrocarbon-producing source rock, the basin also hosts some significant lignite deposits of Giral fen and Kapurdi bog developed during the late Paleocene to early Eocene, being currently under exploitation. Applying organic petrology, geochemical, mineralogical techniques, and Rock-Eval pyrolysis on samples obtained from seams in both mines, the paleodepositional settings in both areas were reconstructed, and the hydrocarbon generation potential was assessed. The Tmax (377–427 °C) and PI (0.01–0.09) values in the studied samples from the Barmer Basin indicate an immature nature of the organic matter. HI values range from 66 to 476 mg HC/g TOC, revealing that the Giral and Kapurdi lignite contains mostly Type III and mixed Type II-III kerogen and can generate mainly gaseous hydrocarbons, although few samples have liquid hydrocarbon generation potential. Significant values of TOC (20–60 wt%) reveal that they may act as a good source of hydrocarbons and make them favourable for the generation of hydrocarbons. The concentrations of major oxides and selected trace elements indicate that the Giral and Kapurdi lignite was developed in warm humid to some extent arid warm climate and oxic conditions prevailed in the basin. Petrographic indices suggest the peat accumulation occurred in a dry forest mire under limnic to limnotelmatic conditions. The indicators further suggest the lignite originated from the bog and fen under mesotrophic to ombrotrophic hydrological condition. The Giral and Kapurdi lignite were determined to be ortho-lignite or low-rank lignite C rank, immature for hydrocarbon generation. The lignite derived mainly from herbaceous vegetation with a higher contribution of woods in the Giral fen compared to the Kapurdi bog. Geochemical indicators suggest the presence of freshwater conditions and a shift from freshwater to brackish water conditions within the basin.

The Effect of Thermal Maturity on the Pore Structure Heterogeneity of Xiamaling Shale by Multifractal Analysis Theory: A Case from Pyrolysis Simulation Experiments

Shale oil and gas, as source-reservoir-type resources, result from organic matter hydrocarbon generation, diagenesis, and nanoscale pore during the evolution processes, which are essential aspects of shale gas enrichment and reservoir formation. To investigate the impact of diagenetic hydrocarbons on shale pore heterogeneity, a thermal simulation of hydrocarbon formation was conducted on immature shale from the Middle Proterozoic Xiamaling Formation in the Zhangjiakou area, covering stages from mature to overmature. Nuclear magnetic resonance (NMR) instruments analyzed the microstructure of the thermally simulated samples, and the multifractal model quantitatively assessed pore development and heterogeneity in the experimental samples. The results reveal that the quartz and clay mineral contents show alternating trends with increasing temperature. Organic matter dissolution intensifies while unstable mineral content decreases, promoting clay mineral content development. Pyrolysis intensity influences Total Organic Carbon (TOC), which reduces as hydrocarbons are generated and released during simulation. Porosity exhibits a decreasing–increasing–decreasing trend during thermal evolution, peaking at high maturity. At maturity, hydrocarbon generation obstructs pore space, resulting in higher levels of bound fluid porosity than those of movable fluid porosity. Conversely, high maturity leads to many organic matter micropores, elevating movable fluid porosity and facilitating seepage. Shale pore heterogeneity significantly increases before 450 °C due to the dissolution of pores and the generation of liquid and gas hydrocarbons. In the highly overmature stage, pore heterogeneity tends to increase slowly, correlated with the generation of numerous micro- and nano-organic matter pores.

Geochemical features of organic matter in the Lower Cretaceous deposits of the Ozhoginskaya Suite (Indigiro-Zyryansky basin)

Limited available data on molecular geochemistry indicate the predominance of terragenous organic matter in the source material of the Lower Cretaceous deposits of the Ozhoginskaya suite, which allows it to be considered gasgenerating. However, based on the mixed nature of the source material, this suite could possess potential for liquid hydrocarbon generation. The geochemical features of the organic matter were studied using classical bituminology, Fourier transform infrared spectroscopy, gas chromatography, and mass spectrometry. The results showed a regular distribution of alkanes with a predominance of low-molecular-weight homologues with a maximum at nC15-19 and low values of ∑n.c.-nC20/∑nC21-c.c., vanadylporphyrin complexes. Thus, the contribution of algal material could be significant to the composition of the fossil organic matter of the Lower Cretaceous Ozhoginsky suite with different ratios of terrigenous and aquatic components in the section. Our results on the Ozhoginskaya suite showed the similarity of geochemical parameters with the Upper Bastakh suite of the Upper Jurassic, the features of bitumoid composition, which were mainly due to the predominance of planktonic-algal material capable of generating a large amount of liquid hydrocarbons. This established similarity raises the estimate of the oil generation potential of the organic matter of the Lower Cretaceous deposits of the Ozhoginskaya suite, along with the high gas generation potential inherent in terragenous organic matter.

ГЕОХІМІЧНІ ТРИГЕРИ ВИКИДІВ ВУГІЛЛЯ ТА ГАЗУ ЗА РЕЗУЛЬТАТАМИ ТЕРМОЛІТИЧНОГО АНАЛІЗУ ROCK-EVAL

Purpose. Investigation of the conditions for the occurrence of coal and gas outbursts from a geochemical point of view. Methodology. The paper examines and analyses the results of determining bituminous and hydrogen indices using the Rock-Eval thermolytic analysis method on safe and dangerous areas of coal seams in terms of coal and gas outbursts. Results. It was established that on safe mining seams, coal samples are within the oil window, where microcracks in the coal mass may still contain films of sorbed bituminous components (liquid hydrocarbons), which counteract the accumulation of energy of elastic deformations and the localization of gas accumulation. However, the transition from the area of liquid hydrocarbon generation to the gas window leads to a sharp increase in the volume of generated hydrocarbon gases, mainly due to the cracking of liquid hydrocarbons, that is, the emergence of geochemical triggers for the localization of coal and gas outbursts during coal mining. Scientific novelty. The new experimentally determined values of bituminous and hydrogen indices for coal seams of the Donetsk basin, and their comparison with the results within safe and dangerous mining seams, demonstrate the fact that all the studied coal samples from outburst-prone areas geometrically lie in the area of the gas window, starting from the moment of cracking of already formed liquid hydrocarbons and subsequent generation of dry hydrocarbon gases (mainly methane) due to the thermal degradation of higher carbon compounds first, and then low carbon compounds (wet hydrocarbon gases) and direct generation from the kerogen matrix. Practical significance. Established geochemical criteria that determine the conditions for the occurrence of gas-dynamic phenomena - outbursts of coal and gas during coal mining. Key words: coal and gas outbursts, bitumen index, hydrogen index, microcracks, hydrocarbon generation, gas window.

Hydrocarbon generation and potential of marine source rocks in supercritical water

Water, in ultra-deep layers of the earth and in layers receiving abnormally high heat, can exist in a supercritical state. Supercritical water (SCW) can participate in the transformations of organic compounds not only as a solvent but also as a reactant, influencing petroleum formation and the evolution of sedimentary organic matter. Here, we carried out hydrous pyrolysis experiments in both SCW and water vapor (WV) using two organic-rich marine rocks under closed conditions, to quantitatively evaluate the generation potential of hydrocarbons in a supercritical state and to clarify the effect of water phase on hydrous pyrolysis experiments. The results showed that SCW promoted gaseous and liquid hydrocarbon generation and facilitated the cracking of aliphatic hydrocarbons. For gaseous hydrocarbons, the action of SCW became stronger as the temperature increased. For liquid hydrocarbons, the peak yields of bitumen were enhanced by the SCW, and the temperature corresponding to peak yield in SCW was lower than that in WV. These results were attributed to the supply of hydrogen and oxygen from SCW for the petroleum formation and cracking. The δ13C and δD values of gases were also influenced by SCW. However, these values obtained in SCW did not always become positive as their yields increased. Generally, methane (CH4) was enriched in 12C and 1H. The influence of SCW on the isotopic fractionation of ethane (C2H6) and propane (C3H8) was more complex. The water phase is an important factor affecting the experimental results of hydrous pyrolysis. From these findings, it can be concluded that SCW allowed for increased conversion of sedimentary organic matter to gaseous and liquid hydrocarbons in ultra-deep layers and layers affected by volcanic-hydrothermal activity.

The evolution of pore structure heterogeneity during thermal maturation in lacustrine shale pyrolysis

Although pore structure variations during thermal maturation have been extensively discussed using natural or artificially matured shale samples, related investigations into pore structure heterogeneity and its evolution remain scarce, posing challenges in fine reservoir evaluation and exploration target prioritization. The variation of pore structure heterogeneity during thermal maturation was determined in this study by integrating multifractal theory with nitrogen adsorption-desorption tests using the naturally immature sample and the artificially matured samples, and the governing factors were ascertained. The increasing thermal maturity results in organic matter transformation, hydrocarbon generation, retention and expulsion, and various types of pore formation, driving the variation of pore structure heterogeneity. Pore structure heterogeneity, quantified by the breadth of singular spectra, was chiefly impacted by the pore volume difference between diverse types of pores. Macropores make a main contribution to pore structure heterogeneity due to their higher percentage of total pore volume compared to mesopores and micropores. Through a comparison of pore structure heterogeneity in shale samples with different thermal maturity, the impact of thermal maturity on shales was clarified. At immature to low-mature stages, nonthermal maturity factors make a main contribution to the inherent pore structure of different shales and cause an ambiguous relationship between pore structure heterogeneity and thermal maturity. At mature to high-mature stages, pore structure becomes more heterogeneous with increasing thermal maturity, resulting from newly formed organic pores or dissolution pores and the progressive generation and expulsion of liquid and gaseous hydrocarbons. At the over-mature stage, pore structure heterogeneity decreases and then fluctuates on a small scale, related to the collapse of mesopores and macropores caused by compaction and the predominance of newly formed micropores.

Oil generation model of the liptinite-rich coals: Palaeogene in the Xihu Sag, East China Sea Shelf Basin

Hydrocarbon generation from liptinite-rich coal is an important focus in petroleum geology as well as in coal geology. The confined pyrolysis experiment in gold tubes is an effective approach in assessing the hydrocarbon generation potential of coals. Xihu Sag is one of the most hydrocarbon-rich Cenozoic basins in the East China Sea Shelf Basin, and oil and gas are believed to be generated from Paleogene liptinite-rich coals. Coals from the Pinghu and Huagang formations of the Paleogene have a liptinite content mostly higher than 10%, and contain type II-III organic matter. The HImax values, H/C, and O/C ratios of these coals are in the range of 200–300 mg/g·TOC, 0.97 to 1.42, and 0.08 to 0.20, respectively. All these characteristics demonstrate good potential for these coals to generate oil. Experimental data show that the maximum cumulative yields of oil produced range from 122.74 to 154.09 mg/g·TOC, and the coals in the sag can also generate oil in their immature stage (Ro = 0.36%–0.5%) due to abundant resinite (mostly higher than 5%). To further assess the characteristics and processes of petroleum generation under geological conditions, we reconstructed the liquid hydrocarbon generation history of the coals in three structural units of Xihu Sag, i.e., the West Slope Belt, West Sub-sag, and Central Anticlinal Belt. For the coals in the Pinghu Formation, the West Slope Belt is a favorable oil-forming area, while the West Sub-sag and the Central Anticlinal Belt are less favorable oil-forming areas. For the coals in the Huagang Formation, the West Slope Belt is a favorable asphaltene (ΣC14+)-forming area, while the West Sub-sag and Central Anticlinal Belt are favorable light hydrocarbon (ΣC6-14)-forming areas. Results of this study will contribute to a better understanding of the characteristics and potential of oil generation from the liptinite-rich coals and are of significance for oil exploration in the Xihu Sag.

Hydrocarbon source rock assessment of the shale and coal bearing horizons of the Early Paleocene Hangu Formation in Kala-Chitta Range, Northwest Pakistan

The present study aims to investigate the origin, type, thermal maturity and hydrocarbon generation potential of organic matter and paleo-depositional environment of the Early Paleocene (Danian) Hangu Formation outcropped in the Kala-Chitta Range of Northwest Pakistan, Eastern Tethys. Organic-rich shale and coal intervals were utilized for geochemical analyses including TOC (total organic carbon) and Rock–Eval pyrolysis coupled with carbon (δ13Corg) and nitrogen (δ15Norg) stable isotopes. The organic geochemical results showed that the kerogen Type II (oil/gas prone) and Type III (gas prone) dominate the investigated rock units. The TOC (wt%) and S2 yield indicate that the rock unit quantifies sufficient organic matter (OM) to act as potential source rock. However, the thermal maturity Tmax°C marks the over maturation of the OM, which may be possibly linked with the effect attained from nearby tectonically active Himalayan Foreland Fold-and-Thrust Belt system and associated metamorphosed sequences. The organic geochemical analyses deciphered indigenous nature of the OM and resultant hydrocarbons. The δ13Corg and δ15Norg stable isotopic signatures illustrated enrichment of the OM from both marine and terrestrial sources accumulated into the Hangu Formation. The Paleo-depositional model established using organic geochemical and stable isotopic data for the formation supports its deposition in a shallow marine proximal inner shelf environment with prevalence of sub-oxic to anoxic conditions, a scenario that could enhance the OM preservation. Overall, the formation holds promising coal and shale intervals in terms of organic richness, but due to relatively over thermal maturation, it cannot act as an effective source rock for liquid hydrocarbon generation and only minor amount of dry gas can be expected. In implication, the results of this study suggest least prospects of liquid hydrocarbon generation potential within Hangu Formation at studied sections.

Organic matter characteristics and hydrocarbon generating potential of the Miocene Belait Formation, Brunei-Muara district, Brunei Darussalam

The characteristics of the source rocks in the early to late Miocene Belait Formation of Brunei Darussalam have been evaluated through the application of Rock-Eval and biomarker analyses, as well as by organic petrographical examination. Analyses have been performed on coal, coaly shale/carbonaceous claystones and shale samples from the Formation, retrieved from outcrops across the Brunei-Muara district, and covering a wide lateral extension of the Formation. The geochemical results indicate that the coal and some carbonaceous samples (with TOC from 14.1% to 67.7%) from the Belait Formation have “good to excellent” generating potential, quantity and quality, due to their high S2 and TOC values, which are consistent with the intermediate hydrogen index (HI) values ranging from 144 to 258 mg HC/g TOC. Organic material of “fair to good” quantity, quality and hydrocarbon generating potential is recorded for the coaly shale samples in the Belait Formation. Non-coal samples generally have the lowest potential as source rocks, due to their low TOC, HI and S2 values. Within the Formation, the coal layers together with a number of coaly shale and shale layers contain type III (gas prone) and type II-III (mixed oil and gas) kerogens. This is proven by the dominance of huminite, often of fluorescent varieties, which is confirmed though maceral analysis, as well as a trend of n-alkanes skewed towards heavier compounds. Evidence of the possible generation of liquid hydrocarbon is offered by the fact that liptinite is the second most abundant maceral group in most of the samples, as well as by the perhydrous nature of part of the huminite. Furthermore, kerogen type IV (dry gas) has been identified in a majority of the coaly shale samples. Facies analysis of the Belait Formation through the use of maceral indices and biomarkers data indicates that the coals were deposited in a mangrove setting in a lower delta plain, where mainly herbaceous and arboreal plants were growing. The depositional conditions were predominantly oxic, with a possible marine influence, and hence brackish conditions. All samples are found to be thermally immature to early mature, with Tmax values ranging from 356 °C to 441 °C, huminite reflectance values of up to 0.46% and high carbon preference index (CPI) values.

Effects of inherent pyrite on hydrocarbon generation by thermal pyrolysis: An example of low maturity type-II kerogen from Alum shale formation, Sweden

To resolve the controversy of iron sulfide effect on hydrocarbon generation of kerogen, a confined anhydrous pyrolysis experiment was performed on an Alum kerogen before and after the removal of kerogen-associated inherent pyrite within a temperature range of 336 ℃ to 600 ℃ at 50 MPa. The effect of kerogen-associated inherent pyrite on hydrocarbon generation and the reaction mechanism were explored by comparing the results from pyrite-contained kerogen with pyrite-removed kerogen. The thermal transformation of pyrite into pyrrhotite gradually increased with increasing temperature, particularly in the range of 432 ℃ − 528 ℃, accompanied by the formation of nascent sulfur. The bitumen/heavy hydrocarbons (C14+) yield was lower in the pyrite-contained (imbedded) kerogen due to strong bonding interaction between pyrite and kerogen. The temperature of peak liquid hydrocarbon (C6-14) production in the pyrite-contained kerogen was nearly 50 ℃ lower than that of the pyrite-removed kerogen, indicating that inherent pyrite accelerated the generation of liquid hydrocarbons. The wet gas yield (∑C2-5) decreased significantly for the pyrite-contained kerogen above 432 ℃, caused by the hydrogen abstraction of additional nascent sulfur. Moreover, the presence of inherent pyrite significantly increased the iso- to normal paraffin ratios (iC4/nC4, iC5/nC5).

Correlation between the Stretching Vibrations of Aliphatic Groups and the Structural and Geochemical Properties of Crude Oils of the Same Genetic Type Using the Case of the Turija-Sever Oil Field, Pannonian Basin, Serbia

The paper describes an investigation of structural and geochemical properties of genetically similar crude oils from the Turija-sever field located in the South-Eastern Pannonian Basin, Serbia. Samples from 56 wells were examined by infrared spectroscopy (IR) and gas chromatography (GC). The IR spectral region of 2800– 3000 cm–1 was modeled by the sum of Lorentzian functions to reveal the contributions of aliphatic stretching vibrations, from which the alkane branching factor was evaluated. Being dependent on the aliphatic chain branching, the CH2 absorption peaks shifted by 3–4 cm–1 towards high frequencies when passing from the least-branched to the most-branched oil samples. This is associated with an increase in the fraction of gauche-conformations in polymethylene fragments. GC data shows the similarity of Turija-sever oils in thermal maturity, corresponding to to the early stage of liquid hydrocarbon generation and revealing a mixed aquatic-terrigenous origin of the precursor organic matter (OM) generated in a transitional reducing to weakly oxidizing depositional environment. In view of a significant correlation revealed between the alkane branching and the geochemistry, the samples were readily divided into two groups. Specifically, oils of Group I have a higher contribution of algae to the precursor OM and were generated under more reducing conditions than oils of Group II. The obtained data demonstrates in practice the advantage of the GC-IR combination to explain the structural and geochemical properties of sedimentary OM.

Organic and Isotopic Geochemistry of Evaporites and Shales of the Santana Group (Araripe Basin, Brazil): Clues on the Evolution of Depositional Systems and Global Correlation during the Lower Cretaceous

Even being the more studied of the interior basins of Northeast Brazil, the Araripe Basin still lacks research in organic geochemistry designed to support interpretations of depositional systems and conditions of formation. This work aims to investigate the organic behavior of evaporites and shales from the Santana Group (Lower Cretaceous), as well as discuss their role in the evolution of its depositional systems. A total of 23 samples, 17 shales and six evaporites, were collected in outcrops and quarries. Analyses of Total Organic Carbon (TOC), Total Sulfur (TS), Rock Eval pyrolysis, and the δ34S isotope ratio were performed. The TOC results revealed high organic content for seven intervals, of which only five had high TS content. From the Rock Eval pyrolysis, dominance of the Type I kerogen was verified, thus corresponding to the best type of organic matter (mainly algal) for the generation of liquid and gaseous hydrocarbons. The Lower Cretaceous (probably Aptian) response to the progressive evolution in redox conditions is linked to a remarked Oceanic Anoxic Event (OAE-1a). The TOC/TS ratio suggests variable palaeosalinity, indicating most of the shales were formed under brackish waters with saline influence, yet tending to increase the salinity upwards where hypersaline conditions dominate in the Ipubi Formation. The isotope data also suggest the occurrence of marine ingressions in the depositional systems even prior to the well-documented event of the Romualdo Formation.

Elements of regional organic geochemistry and separate prediction of oil and gas content of regions

The article considers the elements of organic geochemistry in the regional aspect, which aims to separate quantitative prediction of oil and gas content of regions. The principles and results of balance calculations of generation and emission of liquid and gaseous hydrocarbons for different facies-genetic types of organic matter and methods for calculating the scale of hydrocarbon emission are considered. Finally, a list of the main regularities of organic geochemistry is given.

Elements of regional organic geochemistry and separate prediction of oil and gas content of regions

The article considers the elements of organic geochemistry in the regional aspect, which aims to separate quantitative prediction of oil and gas content of regions. The principles and results of balance calculations of generation and emission of liquid and gaseous hydrocarbons for different facies-genetic types of organic matter and methods for calculating the scale of hydrocarbon emission are considered. Finally, a list of the main regularities of organic geochemistry is given.

Thermal maturation, mineral catalysis, and gas generation kinetics of carbonate source rock

Source-rock evaluation must start by first characterizing thermal maturity. The concept of thermal maturation or thermal decomposition is a well-defined quantitative modelling of kinetic parameters to explain the generation and expulsion of liquid and gaseous hydrocarbons from sedimentary source rocks. However, unlike coal and shale source rocks, carbonate source rocks are emerging source rocks and no analyses of thermal maturation kinetics have been reported in the literature. Apparently, this study is one of the most recent and first laboratory study of thermal maturation kinetics of carbonate source rock. In this paper, we simulated this process by conducting controlled laboratory experiments under high temperature from 40 °C to 450 °C using advanced integrated analytical techniques. The dataset is modeled by the solid state kinetics of first order reactions. In addition, the poor knowledge of how catalytic minerals stimulate thermal maturation is investigated; a unique and significant contribution that sets this work apart from previous thermal maturation studies. The result from kinetic modelling showed that the distribution of activation energy in the range of 99–325 kJ/mol is bimodal, reflecting possible peak shift in the thermal decomposition process, reaction mechanism and maturation prediction. The model further suggests that the maturation process of carbonate-rich source rock is very likely to be different from that of clay-rich source rock. Elemental and mineralogical analyses of investigated sample revealed the presences of catalytic elements such as iron, gypsum, pyrite and kaolinite. The analysis of the generated gases constrained to only three gases showed that the volume content of carbon dioxide, methane and water are 2%, 46% and 52% respectively. The generation of carbon dioxide is constant whereas methane increases and water decreases respectively with thermal maturation. Although, the investigated sample has a high calcite content of 91.9%, the methane content of 46% gives a strong indication of high natural gas generative potential as contrasted with the 2% of carbon dioxide generated. The findings of this study can help to better understand the coupled mechanism controlling thermal maturation of carbonate source rock and also provide useful reference dataset for basin modelling of carbonate source rocks for field studies.

Organic petrography of Ordovician - Silurian rocks and their implications to hydrocarbon generation in the Akkas-1 well, western Iraq: New evidence for the Ordovician Gloeocapsomorpha and glaciation events

The Ordovician-Silurian hot shales are proved to be source for hydrocarbon in Akkas Field. New set of core samples of these important strata from Khabour and Akkas formations were examined from Akkas-1 well by organic petrography. The core samples of the Ordovician were found to be enriched in the liptinitic macerals that are mostly telalginite and lamalginite with lower abundances of vitrinite-like, inertinite and non-fluorescing network-forming matrix bituminite macerals. The studied Ordovician samples showed organic matter composition with large liquid hydrocarbon generation potentiality. The telalginite grains belong to the mat-forming algae that are found mostly in clusters and colonies. The early colonies are assigned to the Ordovician cosmopolitan Gloeocapsomorpha cyanobacterium. Several morphological variations in the telalginite particles are noticed through time that verifies their evolution. This is first record of this important oil prone organic matter in this region. In addition, unique micro-laminae are identified and attributed to the record of seasonal changes or varves. These varves indicate the summer/winter cyclic changes accompanied the Late Ordovician glaciation at western part of Arabian Peninsula and its influence on sedimentation in nearby basins. This cyclic pattern is also recorded for the first time as glaciation evidence in the Akkas-1 well. The seasonal changes of the summer/winter cycle are accompanied with some distinctions in the quantity and quality of the telalginite particles. The summer micro-laminae have large abundance of both organic matter and liptinite maceral. The Silurian hot shale has abundant liptinite maceral that are mostly bituminite and lamalginite. In addition, they are rich in redox sensitive trace elements that reveal anoxic depositional conditions. Ultralaminar structures are documented for the time in the bituminite of Silurian shale, which suggest a micro-algal origin. The source rock in the Silurian shale has a large potentiality to generate liquid hydrocarbon.

Compositional, geochemical and petrophysical shale play characterization of the Upper Cretaceous in southern Middle Magdalena Valley (MMV) basin, Colombia

The compositional, geochemical and petrophysical characterization of a stratigraphic section from the Coniacian-Campanian in the South of the Middle Magdalena Valley basin allowed identifying the potential of this area for unconventional shale reservoirs.Siltstone facies composed of bio-mudstone with organic matter and micrite, and silty mudstone microfacies with foraminifera, showed the best conditions. Rock-Eval results showed a Type II Kerogen with TOC values that range between 2% and 4% and thermal maturity of 0.8% Ro, which demonstrates an optimal maturity level for liquid hydrocarbon generation of this section. Compositionally, the upper part is characterized by high quartz content, whereas the middle section has high calcite content enhancing the mechanical properties of the rock in the event of hydraulic fracturing. The petrophysical analysis indicated optimal values for intergranular porosity favoring hydrocarbon storage. Data integration indicated at least two intervals with high potential for shale oil within the sequence studied.