Source Rock Thermal Maturity Research Articles

Evaluating the reliability of solid phase extraction techniques for hydrocarbon analysis by GC–MS

Saturate and aromatic compounds are essential in the petroleum industry for assessing the thermal maturity of source rocks and oils, which is critical for basin modeling and sweet-spot mapping. These compounds also play a role in environmental applications, such as oil spill fingerprinting and biogeochemistry. However, the analysis of these compounds by gas chromatography-mass spectrometry (GC–MS) requires meticulous and time-consuming separation processes. Traditional methods like normal-phase liquid column chromatography (LCC) involve large volumes of harmful solvents. This study evaluates the effectiveness of five different sorbents using solid-phase extraction (SPE) techniques—neutral Si, SiOH, Ag-ion, neutral Al, and Ag-ion mixed with activated silica—compared to LCC. The goal was to discern differences in peak resolution, concentration, and isomer ratios of saturate and aromatic compounds for thermal maturity and source rock assessments. The results show that SiOH, neutral Si, and neutral Al do not fully separate aromatic compounds from the saturate fraction, sometimes leaving 40–100% of aromatics within the saturate fraction. Ag-ion mixed with activated silica provided the best separation, resulting in up to 23 times higher aromatic concentration than SiOH. This method is more reliable for quantifying both saturate and aromatic compounds, increases the efficiency of hydrocarbon evaluations, and reduces solvent consumption by 63%, offering a more sustainable approach to hydrocarbon analysis.

Evaluation of thermal maturity of source rock based on geochemical method, a case study of Late Oligocene source rock in Hoa Tra field, Cuu Long basin, Vietnam

The  Hoa Tra field is located in the southeast of the Cuu Long basin which has great potential for oil and gas. The source rocks in this area are mainly fine-grained sediments from the late Oligocene and early Miocene, which are located in a continuous deposition zone and under anaerobic conditions. This paper focuses on studying the maturity level of late Oligocene source rock through geochemical analysis methods. Specifically, the paper uses indicators such as T­, R<sub>o</sub>, MPI-1, T<sub>s</sub>/(T<sub>s</sub>+T<sub>m</sub>) and C<sub>29 </sub>steran 20S/(20S+20R) from Rock-Eval Pyrolysis, Vitrinite reflectance and Gas chromatography-Mass spectrometry methods, respectively, to evaluate the level of thermal maturity of the source rock. The source rocks in the Hoa Tra field mainly contain types I and II, which are poor in vitrinite particles, leading to low R<sub>o</sub> measurement results. However, when R<sub>o</sub> is calculated from T<sub>max </sub>and (MPI-1), it indicates that the thermal maturity of source rock from the upper part of the late Oligocene is in the early mature stage (R<sub>o avg</sub>= 0.56%), while those from the lower part of late Oligocene are mature and in the phase of oil generation (R<sub>o avg</sub>= 0.65%). These results are similar to those obtained from assessing thermal maturity using T<sub>s</sub>/(T<sub>s</sub>+T<sub>m</sub> and C<sub>29 </sub>20S/(20S+20R) indicator (the average values for the respective parameters are 0.32 and 0.31 for the upper part, while those are 0.39 and 0.42 for the lower part of late Oligocene). The article also shows that the contribution to the  Hoa Tra field is not only from in-situ generated oil but also from migratory oil coming from nearby troughs.

OIL FAMILIES AND GEOCHEMICAL COMPOSITION OF DEVONIAN OILS AT THE RECHITSA FIELD, PRIPYAT BASIN, BELARUS

The sedimentary column at the Rechitsa oilfield in the Pripyat rift basin, Belarus, is dominated by an Upper Devonian synrift succession. The succession includes uppermost Frasnian and mid‐Famennian salt units which are about 1000 m and 2000 m thick respectively. Reservoir rocks consist of sandstones and carbonates in the intra‐, inter‐ and sub‐salt successions. In this paper, the geochemical analysis of 15 oil samples from different stratigraphic intervals at the Rechitsa field is used as a basis for reservoir characterisation. Geochemical studies included biomarker and stable C, N and S isotope analyses.Four genetic oil groups were identified and are referred to as Groups A to D. Oils in Group A came from upper intra‐ and inter‐salt reservoir rocks; the oils are early mature, enriched in heavy (C36+) hydrocarbons, heteroatoms, aryl‐isoprenoids and gammacerane, with low Pr/Ph = 0.6 and a sulphur isotope composition averaging 22.7‰ CDT. Oils in Group B were from sub‐salt reservoirs and are at peak maturity with Pr/Ph = 1, an increased proportion of C27 regular steranes, and a sulphur isotope composition of 8.1‰ CDT. The single oil sample in Group C was from a Proterozoic reservoir. The oil was overmature with a low content of heavy fractions, heteroatoms and steranes; its hopanes composition indicated that it was generated by the same source rock as the oils in Group B. Oils in Group D came from inter‐salt reservoir rocks and were composed of a mixture of Groups A and B oils in roughly equal proportions, as indicated by their average isotope, molecular and biomarker compositions.Observed differences in oil composition were explained in terms of contributions from at least two different source rocks together with variations in source rock maturity. Group A oils were interpreted to have been generated by Famennian carbonate‐rich source rocks containing dominantly marine and bacterial organic matter deposited in an anoxic evaporitic setting. Source rocks for Groups B and C oils were suggested to be composed of OM‐rich marine shales of Frasnian age or older.The geochemical characteristics of the Devonian oils from Rechitsa field, and the oil‐oil and oil‐ source rock correlations reported, will contribute to a better understanding of the petroleum system in the Pripyat Basin although direct oil‐ source rock correlations are not yet available. The presence of at least two source rocks for the Rechitsa oils has been suggested, respectively comprising carbonates in the inter‐salt succession and marine shales and/or carbonates in the sub‐salt succession. The main controls on oil composition in the Devonian reservoir units were the varying contributions from the different source rocks and differences in source rock thermal maturity associated with variations in burial depth and tectonics, together with the stratigraphic distribution of reservoir units which was in turn controlled by the presence of the thick Frasnian and Famennian salt units.

Predicting the thermal maturity of source rock from well logs and seismic data in basins with low-degree exploration

Vitrinite reflectance (Ro) is a significant geological index that evaluates the thermal maturity of source rock. However, measured Ro data and suitable evaluation methods are lacking, making it difficult to predict the thermal maturity of source rock in basin, especially in those with a low exploration degree. In this study, we propose a novel method for estimating Ro from well logs and seismic data using seismic velocity inversion and the vitrinite reflectance-mudstone porosity (Ro-ϕ) model. First, using a wavelet neural network, acoustic transit time curve was reconstructed from spontaneous potential, gamma rays, resistivity, and density logs, and new curve was used as inputs in a colored inversion to obtain seismic relative velocity. Second, a low-frequency model was established to counteract critical frequency and sequence framework constraints. Third, the seismic absolute velocity was merged by relative and low-frequency velocity components. Finally, Ro distributions were calculated using the Ro-ϕ model. Our findings indicate that the inversion effect improved with low-frequency supplement; compared with the graphic and geochemical method, the Ro-ϕ model predicted Ro in poor-data areas more accurately, with a relative error of <9.5205%. We also propose an explanation for the appearance of highly mature source rocks distributed from dispersion to aggregation in depression-rift transitions: the thick stratum in the downthrow wall of boundary faults promote source rock maturity in the rift period; hence, in an open depression, the source rocks in large subsidence areas are highly mature, particularly near the downthrow wall of a boundary fault, which has the highest maturity owing to the superimposed subsidence of the overlying rifted basin.

Lithostratigraphic Interpretation, Geotemperature Analysis, and Hydrocarbon Windows Determination in Seloken Field, Chad Basin, Northeastern Nigeria

The aim of this study is to interpret the lithostratigraphic units, analyze geotemperature and determine the hydrocarbon windows in the Seloken Field. Gamma-ray logs and formation tops were used to interpret the lithostratigraphic units. Corrected bottom hole temperature (BHT) data from the wells were used to calculate the geothermal gradients. A formular was derived from the geothermal gradient equation to analyze the geotemperature. Another formular was derived from the geotemperature equation to obtain the hydrocarbon windows. Five major lithostratigraphic units were interpreted. They are: Bima and Gongila Formations, Fika Shale, Kerri-Kerri and Chad Formations…The calculated geothermal gradients range from 3.4oC/100m to 4.0oC/100m, with an average of 3.65oC/100m and the standard deviation of 0.01oC/100m. The temperature of shale units of the formations at various depths calculated from the geotemperature equation range from 30.99oC to 202.45oC. This shows that some of the shale units are thermally mature to cook petroleum The oil window calculated from the derived geomathematical equation is between 1178.1m and 2457.95m, while the gas window is from 2457.95m to 5424.7m. The boundary between the two windows is at 2457.95m. The results above were used to generate a hypothetical model for the hydrocarbon windows. The model indicates that the shale units are within the diagenesis and catagenesis phases. This work provides mathematical methods of source rock thermal maturity evaluation to complement geochemical methods. The outcome is a very important tool, which can be applied to other fields and sedimentary basins in hydrocarbon exploration.

PALYNOFACIES AND ORGANIC GEOCHEMISTRY OF LACUSTRINE SOURCE ROCKS: THE POTRERILLOS – CACHEUTA SOURCE ROCK SYSTEM IN THE TRIASSIC CUYO BASIN, WEST‐CENTRAL ARGENTINA

This study presents an integrated investigation of the Upper Triassic Potrerillos – Cacheuta lacustrine source rock in the Cuyo Basin of western Argentina. Data came from palynofacies analyses, organic petrography, Rock‐Eval pyrolysis and mineralogical studies based on X‐ray diffraction analyses. An 80 m thick outcrop section was studied and is interpreted to represent the transition from shallow‐lacustrine sediments influenced by fluvial discharges (uppermost Potrerillos Formation) to the deposits of a deep, permanent lake (Cacheuta Formation). Three palynofacies were defined. Palynofacies I is characterized by shallowing‐upward cycles with abundant woody material, and was deposited under an oxic, disturbed water column. Palynofacies II and III occur in laminated shales rich in amorphous organic matter (AOM) and freshwater algal material (Botryococcus) respectively, which were deposited under oxygen‐depleted conditions. In general, the detrital material present suggests an input derived from fluvial discharges; however, interbedded tuffs altered to analcime and smectite suggest the transformation of vitric material in pyroclastic ash under saline to alkaline water conditions. Kerogen Types II/III and III with high total organic carbon values indicate a moderate oil‐ and gas‐prone source rock whose thermal maturity varies from immature to the early oil window (Tmax: 430‐438 °C; vitrinite reflectance: 0.59‐0.67 % VRo; and thermal alteration index: 2‐2+).This study demonstrates the importance of palynofacies analyses for the interpretation of depositional changes and associated controls in lacustrine shale successions. When integrated with data from organic geochemistry, palynofacies analysis is an important tool in the evaluation of a source rock's thermal maturity and hydrocarbon generation potential.

Evaluation of portable Raman spectroscopic analysis for source-rock thermal maturity assessments on bulk crushed rock

This study presents a simplified method and empirical relationships for determining organic matter thermal maturity using a portable Raman system equipped with a 785 nm laser, for analysis of crushed, whole-rock samples. Suites of rocks represented by shale and coal samples with various mineralogical composition, thermal maturity, and total organic carbon (TOC) were used to test the method and build correlations between Raman band separation (RBS) values and traditional thermal maturity indicators, organic matter reflectance (Ro), and programmed temperature pyrolysis (Tmax) values. A set of disparate shale samples, where both vitrinite and solid bitumen reflectance values were reported, have Ro values that range from 0.40 to 4.62%. Above 3.35% Ro, the corresponding RBS values plateau at ∼290 cm−1, thus correlations were evaluated with a linear regression (R2 = 0.96) between 0.40 and 3.35% Ro. Shale samples with Ro < 2% and Tmax < 551 were also used to correlate Tmax and RBS, yielding a linear correlation with an R2 of 0.94. For the coal data set, Ro values range from 1.21 to 4.08% and correlated RBS values plateau at ∼250 cm−1 above Ro = 3.0%, suggesting its correlative application below this maturity level. Several sample preparation methods were tested on cuttings material and standard deviation values for RBS were minimized by washing, drying, and hand crushing the material to pass through a 40-mesh sieve, although less preparation can still yield reliable results. The high degrees of correlation between whole-rock RBS data and two thermal maturity indicators demonstrate the utility of this approach for generating source rock thermal maturity data from minimally processed, whole-rock samples which could easily be applied in field or laboratory settings.

Formation of volatile organic sulfur compounds by low thermal maturation of source rocks: A geochemical proxy for natural gas

Volatile organic sulfur compounds (VOSC) are trace components of natural gas that can provide substantial information regarding gas origins, migration, and key processes such as H2S generation and its occurrence in natural gas reservoirs. In the current study we demonstrate the applicability of VOSC as a proxy for gas-source rock correlations and identification of interactions between H2S and other natural gas components. We studied the molecular and isotopic compositions of VOSC formed during low-level thermal maturation (%Ro equivalent = 0.60–0.71) of six different immature source rocks covering a variety of kerogens (types I, II, II-S and III). Anhydrous pyrolysis experiments (300 °C, 72h) were performed on all the source rocks studied, and the produced gases were analyzed for their molecular compositions and compound specific sulfur isotopes of the various VOSC formed. The formed gases were either dominated by CH4 (32.2–49.9%) or CO2 (31.9–46.2%) and contained a variety of alkanes in the C2–C5 range. H2S formed in 6 out of 8 experiments at concentrations ranging from 0.6 to 4.3%. The results demonstrated formation of VOSC in all experiments, regardless of kerogen types or source rock lithologies. The formation of thiols (16–121.2 ppm) in the produced gas was restricted to those experiments that contained H2S. This indicates that thiols formation is limited to gas-phase interactions between H2S and hydrocarbons. In contrast, thiophenes formed in all experiments (14.9–1778.8 ppm) regardless of H2S presence. Thiols preserved the δ34S signal of their associated H2S due to gas-phase interactions between the two, while thiophenes showed no interaction with the associated H2S and instead preserved the δ34S signature of the bulk kerogen (within 3.5‰ on average) of each source rock. This work demonstrates the applicability of thiophenes to act as a gas-source rock proxy for natural gas and thiols as a proxy for identification of present or paleo-interactions between natural gas and H2S.

The Right Maturity Model for the Norwegian North Sea

Vitrinite reflectance (VR) is routinely measured as an indicator of the thermal maturity of source rocks. Since the 1970s, algorithms that model VR have been used to calibrate thermal models. The modelled thermal history can vary significantly depending on the choice of VR model. Over the last few years, numerous VR models have been proposed and it is unclear which one should be used. The choice of the appropriate VR model is often left to the user or modelling software and is used without determining the suitability of the chosen model for the region or dataset. To avoid such biases, we explore a comprehensive VR dataset from the Norwegian North Sea to determine the VR model that best fits measurements. We use a 1D basin model that simulates VR in the well and combine it with global optimization algorithms to determine which of the currently favoured VR models fits the data best. We find that the Easy%Ro DL model best fits data from the Norwegian North Sea.

Differences on Geochemical Characteristics and Their Implicating Significances of Nitrogen in Coal-Derived Gas and Oil-typed Gas in China

Natural gases in China are mainly coal-derived gas, with assistance from oil-typed gas. At present, many genetic identification methods, from hydrocarbon composition and isotope to light hydrocarbon and biomarker indexes, have been formed, but combined methods from non-hydrocarbon gases are lacking. Based on compositions and isotopes geochemical characteristics and the differences of non-hydrocarbon nitrogen gas in coal-derived gas and oil-typed gas, and combining the isotopic geochemical characteristics of non-hydrocarbon helium, the comprehensive identification methods of coal-derived gas and oil-typed gas for hydrocarbon gases according to the associated non-hydrocarbon gases of nitrogen and helium are established and the preliminary applications have been engaged. The main recognitions are as follows:1)Coal-derived gas generally has relatively lower nitrogen abundance, mainly distributed from 0 to 31.2% with main frequency from 0 to 2%. Oil-typed gas, on the other hand, usually has relatively higher nitrogen abundance, mainly distributed from 1.1 to 57.1% with main frequency from 2 to 16%. 2) Coal-derived gas generally has relatively heavier nitrogen isotope values, mainly distributed from -8 to 19.3‰ with main frequency from -8 to 8‰.Oil-typed gas usually has relatively lower nitrogen isotope values, mainly distributed from -10.6 to 4.6‰ with main frequency from -8 to 4‰.3)The geochemical characteristic differences of coal-derived gas and oil-typed gas are mainly due to the fact that the sapropel parent material is relatively rich in nitrogen element and rich in light δ14N, while the humic parent material is relatively poor in nitrogen element and rich in heavy δ15N. The differences on thermal maturity of source rocks, the redox conditions of source rock sedimentary environment, and the salinity of water body are also important effective factors.4)Differences on nitrogen abundances and isotopes in coal-derived gas and oil-typed gas have great significance in genetic identification. The genetic identification chart of R/Ra-δ15N for organic and inorganic nitrogen in natural gas and the comprehensive joint identification charts of R/Ra-δ15N-N2 of nitrogen and helium for coal-derived gas and oil-typed gas have been established, and are of great reference in investigating the origins and sources of natural gas and guiding natural gas exploration in China.

MATURITY OF POTENTIAL CRETACEOUS SOURCE ROCKS AT THE ISIS FIELD, OFFSHORE EASTERN TUNISIA: INFLUENCE OF HYDROTHERMAL FLUIDS

An increase in source rock thermal maturity is in general linked to burial‐related heating according to the regional geothermal gradient, but maturities may also locally be influenced by high‐temperature hydrothermal fluids or igneous intrusions. In the present study of the Isis field located in the Gulf of Gabes (offshore Tunisia), we combine an analysis of organic matter maturity indicators and clay mineral signatures to constrain possible fluid/rock interactions and to define controls on the maturity of potential source rocks. Cuttings samples were collected from source rock intervals in the Cretaceous Bahloul (Cenomanian – Turonian) and underlying Fahdene (Albian – Cenomanian) Formations at the PM borehole, and detailed organic geochemical and clay mineralogical analyses of source rock samples and extracts were carried out. Samples from the Bahloul Formation (2381 m to 2400 m) consist of black to dark grey claystones and globigerinid limestones. Those from the Fahdene Formation (2400 m to 2700 m) comprise alternating claystones and chalky limestones containing globigerinids including Ticinella primula. Both source rock intervals have similar mineralogical compositions consisting of calcite, quartz, albite, anorthite, minor anatase, pyroxene and pyrite. The clay mineralogy of the formations is composed of abundant smectite (two generations), subordinate kaolinite and minor illite and/or mica. The Fahdene source rock contains organic matter consisting of mixed kerogen Types II/III; Type II OM is present in the Bahloul Formation.At the borehole location, the source rock intervals in the Fahdene and Bahloul Formations have been affected by hydrothermal fluids which are derived from an unconformably overlying basalt succession which is &gt;300 m thick. Based on bulk mineral assemblages, the Bahloul Formation has been modified by the hydrothermal fluids more significantly than the underlying Fahdene Formation. Analyses of the clay minerals compositions indicate that interactions between the hydrothermal fluids and the host rocks were very rapid and were localized within fractures and micropores. The Bahloul Formation source rocks have reached an advanced stage of thermal maturity (overmature or end‐ oil window) compared to the thermally immature source rocks in the Fahdene Formation.The results show that the main control on source rock maturation at the studied well was maximum palaeotemperature and this may locally have been influenced by short‐term hydrothermal and magmatic heating as well as by the regional geotherm. Clay minerals were less affected by hydrothermal heating compared to organic matter indices; this may be because mineral components are slower to react to short‐term higher temperature conditions than organic matter.Thus magmatic activity and hydrothermal fluids may locally accelerate the thermal maturation of source rocks even at shallow depths. The study also shows that a combination of clay mineral characterization and organic matter indicators can be useful for the assessment of thermal maturity in potential source rocks.

Characteristics and implications of Albian volcanism in a magma-rich rift basin: Seismic volcano stratigraphic and geomorphological evidence from the Upper Suhongtu Member in the Chagan Sag, China-Mongolia border region

Buried volcanic successions imaged by 3D seismic data reveal facies components of Albian volcanism in the Chagan Sag of the Yingen-Ejinaqi Basin. The volcanic rocks of the Upper Suhongtu Member are composed mainly of vesicular and tight massive basalts and andesites. Three types of volcanoes, including monogenetic volcanoes, flood basalts, and shield volcanoes were recognized through detailed seismic facies analysis. A seismic geomorphological study showed that volcanism declined from Unit 1 to Unit 2, with the decline being strongly associated with the transition from the rift climax to the later syn-rift phase. In Unit 1, a center-type eruption arose at the onset, and was subsequently overwhelmed by multistage basaltic lavas supplied by fissure vents of the Maoxi, Tulage, and Barun faults in response to increased thermal fluid activity. Several cone- and crater-shaped monogenetic volcanoes formed by the center-type eruption that developed in Unit 2. In addition, a large shield volcano supplied by fissure vents and a major volcanic conduit developed in the northwestern part. The Albian volcanism of the Yingen-Ejinaqi Basin and the whole volcanic province contributed to a much hotter and more arid paleoclimate, and their records can be recognized from palynological and elemental geochemical evidence in the Chagan Sag and its surrounding area. Volcanism not only produced widely distributed strongly heterogeneous volcanic reservoirs but also accelerated the thermal maturation of source rocks, contributing to near-source hydrocarbon accumulation in Lower Cretaceous magmatic-rich rift basins of the East Asian region.

Integration of regional gravity modeling, subsidence analysis, and source rock maturity data to understand the tectonic and hydrocarbon evolution of the Permian Basin, West Texas

The Permian Basin of West Texas and southeast New Mexico is currently the most prolific oil-producing basin in the United States. This region experienced deformation and extreme rates of subsidence (up to 500 m/my), especially during the Late Paleozoic. To investigate the larger scale crustal geometry of the Permian Basin, its tectonic evolution, and the distribution of its most productive late Paleozoic source rocks, we have created regional 2D and 3D gravity models that incorporate density and lithologic controls from wireline logs, published seismic refractions, and regional cross sections. These gravity models better define a regional northeast-trending gravity low called the Abilene gravity minimum (AGM) that underlies the northern Permian Basin. We infer this feature to be underlain by a low-density assemblage of Precambrian granitic and metasedimentary rocks. Structural inversion from the gravity model shows that the top of the lower crust and the Moho is presently depressed beneath the AGM. Subsidence analysis defines five tectonic phases from Cambrian to recent with maximum subsidence during the main, late Paleozoic deformational phase resulting in deposition of sediments up to 2.4 km thick. We have determined that the geobody under the AGM acted as a zone of preferential weakness in a “broken foreland basin” setting that accommodated regional shortening related to the Marathon orogeny and to other coeval orogenies along the Sonoran margin and Nevadan margin. Our new regional map of the top basement defines the limits of deep basinal areas that may host the most productive and thermally mature, late Paleozoic source rock kitchens — some of which are localized in depocenters controlled in part by syncollisional, left-lateral strike-slip faults that align with the edges of the AGM. Our results show a deeper basement ranging from 5.5 to 6.2 km in the Delaware basin that predicts a broader zone of source rock thermal maturity.

Molecular and isotopic gas composition of the Devonian Berea Sandstone and implications for gas evolution, eastern Kentucky

Since 2011, the Devonian Berea Sandstone in northeastern Kentucky has produced oil where thermal maturity studies indicate that likely source rocks, namely, the Devonian Ohio Shale and Mississippian Sunbury Shale, are thermally immature. Downdip, where source rocks are mature for oil, the Berea Sandstone and Ohio Shale primarily produce gas. To investigate this thermal maturity discordancy, the molecular and isotopic composition of gases from the Berea Sandstone (oil associated) and Ohio Shale (nonassociated) were analyzed to understand the gas generation and migration history. Collected along a northwest-southeast transect in eastern Kentucky, samples range from 1079 to 4602 ft, respectively. All are wet gases with a thermogenic origin (δ13C-CH4 e −53.5‰ to −46.1‰). This is mostly consistent with a reevaluation of thermal maturity in a companion study that expands the area mature for oil. Gas migration is required, however, in updip parts of the Berea play where vitrinite reflectance (VRo) values are less than 0.6%. Southeast regional dip exerts a first-order influence on thermal maturity as gases become drier and isotopically heavier downdip. Correlation of δ13C values for heavier hydrocarbon gases in a natural gas plot with VRo contour spacing demonstrates the influence of nearby source rock thermal maturity on gas composition. Downdip, migration of oil and the attendant increase in permeability relative to gas may account for the dominance of gas production in the Ohio Shale. Migration along with basin uplift after the Alleghany orogeny may have contributed to development of a gas phase that exsolved from oil.

Position-specific distribution of hydrogen isotopes in natural propane: Effects of thermal cracking, equilibration and biodegradation

Intramolecular isotope distributions, including isotope clumping and position specific fractionation, can provide proxies for the formation temperature and formation and destruction pathways of molecules. In this study, we explore the position-specific hydrogen isotope distribution in propane. We analyzed propane samples from 10 different petroleum systems with high-resolution molecular mass spectrometry. Our results show that the hydrogen isotope fractionation between central and terminal positions of natural propanes ranges from −102‰ to +205‰, a much larger range than that expected for thermodynamic equilibrium at their source and reservoir temperatures (36–63‰). Based on these findings, we propose that the hydrogen isotope structure of catagenic propane is largely controlled by irreversible processes, expressing kinetic isotope effects (KIEs). Kinetic control on hydrogen isotope composition of the products of thermal cracking is supported by a hydrous pyrolysis experiment using the Woodford Shale as substrate, in which we observed isotopic disequilibrium in the early stage of pyrolysis. We make a more general prediction of KIE signatures associated with kerogen cracking by simulating this chemistry in a kinetic Monte Carlo model for different types of kerogens. In contrast, unconventional shale fluids or hot conventional reservoirs contain propane with an isotopic structure close to equilibrium, presumably reflecting internal and/or heterogeneous exchange during high temperature storage (ca. 100–150 °C). In relatively cold (<100 °C) conventional gas accumulations, propane can discharge from its source to a colder reservoir, rapidly enough to preserve disequilibrium signatures even if the source rock thermal maturity is high. These findings imply that long times at elevated temperatures are required to equilibrate the hydrogen isotopic structure of propane in natural gas host rocks and reservoirs. We further defined the kinetics of propane equilibration through hydrogen isotope exchange experiments under hydrous conditions; these experiments show that hydrogen in propane is exchangeable over laboratory timescales when exposed to clay minerals such as kaolinite. This implies rather rapid transfer of propane from sources to cold reservoirs in some of the conventional petroleum systems. Propane is also susceptible to microbial degradation in both oxic and anoxic environments. Biodegradation of propane in the Hadrian and Diana Hoover oil fields (Gulf of Mexico) results in strong increases in central-terminal hydrogen isotope fractionation. This reflects preferential attack on the central position, consistent with previous studies.

Organic geochemistry and basin modeling of Late Cretaceous Harshiyat Formation in the onshore and offshore basins in Yemen: Implications for effective source rock potential and hydrocarbon generation

The purpose of this study is to present the source rock characteristics of Late Cretaceous Harshiyat Formation source rock in the onshore and offshore basins of Yemen (i.e. Mukalla-Sayhut, Sayun–Masilah , and Jiza-Qamar). Source rock geochemical characterizations were completed and integrated to perform 1-D basin modeling to back-predict source rock thermal maturation, oil generation and expulsion.The geochemical findings revealed that mudstone intervals within the Harshiyat Formation comprised favorable source rocks, with total organic carbon (TOC) content between 0.50 and 35.10 wt %. The organic matter intervals in the Harshiyat mudstones are mainly Types II/III and III kerogens, with certain amount of Type II and I kerogens based on Rock-Eval HI values, ranging from 40 to 923 mg HC/g TOC. Mixed kerogen types were consistent with vitrinite and sapropelic organic matters, as observed by visual kerogen examination and the distribution of biomarker fingerprints. The existence of mixed types I, II, and III organic matter suggests that the Harshiyat mudstones could contribute to oil and gas at sufficient thermal maturity levels. The biomarker data of the organic matter in the Harshiyat mudstones show that the source rock contains a mix marine phytoplanktonic-bacteria/terrestrial land plant enthronement and were deposited in suboxic-anoxic conditions.Results of chemical and optical maturity indicators led to the conclusion of varying maturity stages from immature to late oil window levels for the mudstones of the Harshiyat Formation. Thermal maturation distributions inferred from the analyzed samples indicate that mudstone intervals in the offshore Mukalla-Sayhut Basin are extremely mature, compatible with the late-mature oil window and may have generated significant amounts of oil. This interpretation was supported by strong geochemical similarity between the organic matter in the mudstones and those of the oils found in the offshore Mukalla-Sayhut Basin and demonstrated by the concentrations of n-alkanes and isoprenoids as well as carbon isotopes.In the offshore Ras-Ghashwah-1X well, burial and thermal models were constructed and used to address the effect of tectonic events in triggering oil generation and expulsion from mature Harshiyat source rock in the offshore area. Kinetic database models for Type II and III kerogen mixtures indicate that the initial conversion of kerogen to oil occurred since the Late Oligocene with transformation ratios (TR) that span between 10% and 50%. Furthermore, the oil was expelled from organic matter intervals in the Harshiyat source rock starting from Late Oligocene and continuing until Late Miocene, with TRs of 50%–72%. From that period up to the present, the retained oil was cracked into wet gas in the gas window with an Easy %Ro greater than 1.30, and with peak TR ratios greater than 72%.

Pyrolysis of coal measure source rocks at highly to over mature stage and its geological implications

The influence of water on gas generation from humic type organic matter at highly to over mature stage was investigated with thermal simulation experiments at high temperature and pressure. The result of the experiments indicates that the effect of water on gas generation was controlled by the thermal maturity of organic matter. Water could enhance gas generation and increase hydrocarbon gas yields significantly at over mature stage of humic type organic matter. Hydrogen isotopic compositions of coal-derived gases generated at highly to over mature stage were mainly controlled by thermal maturity of source rocks, but also affected by formation water. Highly and over mature coal measure source rocks are widely distributed in China. The hydrocarbon gas generation capacity of coal measure source rocks and resource potential of coal-derived gases in deep formations would be significantly enhanced assuming that formation water could be involved in the thermal cracking of highly to over mature organic matter in real geological settings.

Geochemical significance of tricyclic and tetracyclic terpanes in source rock extracts from the Offshore Niger Delta Basin, Nigeria

Tricyclic and tetracyclic terpanes are important constituents of crude oil and source rock extracts. However, they have not been reported in the Offshore Niger Delta Basin, Nigeria. Thus, the present study investigated the geochemical significance of tricyclic and tetracyclic terpanes in source rock extracts from the Offshore Niger Delta Bain, Nigeria with gas chromatography-mass spectrometry (GC-MS). The total relative abundances of tricyclic terpanes, C19TT–C21TT, and C23TT in the rock samples ranged from 82.50 to 96.37%, 50.08 to 74.17%, and 25.83 to 49.92%, respectively. These values showed the source rocks were formed from a mixed origin (terrestrial and marine). Among the tricyclic and tetracyclic terpanes identified in the rock extracts, the conventional (C20TT, C23TT, C24TT, C24TeT) and recent (Y1, X1, Z1) were more prominent than all others, indicating mixed input of terrigenous and marine organic matter. The C24TT/C23TT, C24TeT/(C24TeT + C26TT), C19TT/C23TT, C20TT/C23TT, C25TT/C24TeT, C25TT/C26TT, C19TT/C20TT, C24TeT/C26TT, Z1/(Z1 + C24TT), and Y1/(Y1 + C24TT) in the rock samples range from 0.33 to 1.30, 0.76 to 0.90, 0.18 to 0.73, 0.34 to 1.05, 0.33 to 1.74, 0.30 to 1.39, 0.31 to 0.89, 1.66 to 4.33, 0.36 to 0.83, and 0.34 to 0.79, respectively. These values further showed that the rock samples were formed from mixed input of terrigenous and marine organic matter and deposited under oxic to suboxic conditions in lacustrine-fluvial/deltaic environments. Also, the C24TeT/C20–26TT, C24TeT/C30HOP, and C23TT/C30HOP ranged from 0.16 to 0.45, 0.02 to 0.42, and 0.01 to 0.48, respectively. This range of values suggests that source rocks were within immature to early mature stage. Thus, this study showed that tricyclic and tetracyclic terpanes were effective in determining the origin, depositional environments, and thermal maturity of source rocks in the Niger Delta Basin, Nigeria.

Geochemical implications from direct Rock-Eval pyrolysis of petroleum

The maximum burial depth and thermal maturity of a hydrocarbon source rock controls the generation of petroleum, and data on rock maturity are necessary for an understanding of a petroleum system. Rock-Eval pyrolysis is an established method to assess the hydrocarbon generation potential, the type of organic matter (kerogen type), but also the thermal maturity of hydrocarbon source rocks. Data on the thermal maturity of source rocks and/or of the generated hydrocarbons are, however, often lacking either, because (i) the source rock itself is not available or (ii) today’s maturities cannot be directly linked to a generated petroleum, because petroleum generation and expulsion may have taken place at an earlier and less mature stage of the source rock. Indirect records of source rock maturities can be inferred from the physical properties of petroleum (e.g, API gravity), from biomarker abundances or from individual hydrocarbon ratios (including biomarkers). Using an adapted direct Rock-Eval pyrolysis approach for petroleum samples we present data from oils from the BGR petroleum archive. We distinguish between two hydrocarbon release-stages during Rock-Eval pyrolysis of which the first represents a vaporizable mid-molecular (S1oil) fraction (< 400 °C; n-C15 ->n-C40) and the second (S2oil) fraction (> 400 °C; >n-C40) most likely represents a residual higher-molecular weight petroleum fraction generating hydrocarbons by pyrolytic destruction. Using this program, we calculate an “Oil Composition Index” (OCI). Unless processes like biodegradation, evaporation or migration can affect OCI values, in a relatively well known petroleum system without major influences from these processes (the Gifhorn Trough in the Lower Saxony Basin [LSB] in Northern Germany), our data indicate that maturity of the source rock during expulsion is key for OCI. Application of Rock-Eval on a large set of oils from the entire LSB demonstrates that OCI values further hold information on the kerogen-type of the source rock (Wealden vs. Posidonia shales).

Distribution and geochemical significance of dibenzofurans, phenyldibenzofurans and benzo[b]naphthofurans in source rock extracts from Niger Delta basin, Nigeria

The distribution and geochemical significance of dibenzofurans, phenyldibenzofurans and benzo[b]napthofurans in source rocks from Niger Delta basin, Nigeria, were investigated by Rock–Eval pyrolysis and gas chromatography-mass spectrometry (GC–MS). The data obtained from the source rocks evaluation showed that the rock samples contained type II/III kerogen capable of generating oil and gas and were within immature to early mature stage. The relative abundance of the C0-, C1- and C2-dibenzofurans range from 1.75% to 29.82%, 27.60% to 40.52% and 29.66% to 68.89%, respectively. The dibenzofurans were dominated by C2-dibenzofurans. Among the C1-dibenzofurans, 2-+3-methyldibenzofuran was the most abundant in the rock samples while 1-methyldibenzofuran appeared to be the least. The relative abundance of benzo[b]naphtho[1,2-d]furan ([1,2]BNF), benzo[b]naphtha[2,1-d]furan ([2,1]BNF) and benzo[b]naphtha[2,3-d]furan ([2,3]BNF) in the rock extracts range from 12.01% to 52.58%, 32.61% to 75.21% and 10.27% to 52.43%. The wide range of values recorded for the three isomers of benzo[b]napthofurans in the samples suggest source rocks formed from mixed organic matter. Among the phenyldibenzofuran isomers, 4-phenyldibenzofuran was the most abundant while 1-phenyldibenzofuran was the least. Phenyldibenzofuran ratio-1 (PhFR-1) and phenyldibenzofuran ratio-2 (PhFR-2) values range from 0.13 to 1.20 and 0.11 to 2.11, respectively. The results showed that the relative abundance of PhFR-1 and PhFR-2 increase gradually with increasing burial depth and maturity (VR0 ≤ 0.77%, MPI-1 ≤ 0.62, Tmax ≤ 443 °C), and have a good correlations with calculated vitrinite reflectance, MPI-1 and maximum Temperature (Tmax). This range of values suggested immature to early mature source rocks. The source rocks were found to have shale and coal lithologies and deposited in a lacustrine/fluvial/deltaic settings within immature to early mature stages based on the distribution of dibenzofurans, phenyldibenzofurans and benzo[b]naphthofurans in the source rocks. This study showed that dibenzofurans, phenyldibenzofurans and benzo[b]naphthofurans were effective in determining the origin, depositional environment and thermal maturity of source rocks in Niger Delta basin, Nigeria.