This study examines the effect of high water pressure (up to 900 bar) on hydrocarbon generation from Type-I kerogen-rich source rocks and compares the results with previously observed effects on Type-II and Type-III kerogens. An immature Type-I oil shale sample from the Duwi Formation, Egypt, was pyrolysed under anhydrous, low-pressure hydrous, and high water-pressure conditions at 320 degrees C (end of bitumen generation) and 350 degrees C (oil window) for 6 and 24 h, respectively. Pyrolysis at 320 degrees C showed that bitumen generation was promoted in the presence of water under lowpressure hydrous compared to anhydrous conditions but retarded at high water pressures. At 350 degrees C, oil generation was also retarded by increasing pressure, with maximum oil yield at 500 bar before dropping by 72% at 900 bar. Lower bitumen yields at 500 bar and higher yields at 900 bar confirm more retention of oil and bitumen in the rock at higher pressure. High water pressure systematically decreased hydrocarbon gas yields, with a more prominent effect at 320 degrees C because of temperature's dominant impact over pressure at 350 degrees C. Similarly, non- hydrocarbon gas yields decreased as water pressure increased, with maximum yields under anhydrous and low-pressure hydrous conditions. The retardation effect on bitumen generation was less significant than that on oil and gas generation. This study highlights pressure's impact on petroleum generation, particularly in overpressured basins. Elevated pressures on Type-I kerogen source rocks retard oil expulsion, and the retained oil and bitumen within the rock can be directly cracked to gas, suggesting that under such conditions, oil yields may be lower, while unconventional gas resources are likely to be more abundant.

Natural hydrogen has generated great interest as a potential clean and renewable energy source. To understand the occurrence of natural hydrogen, 103 1-m deep soil gas samples were acquired near the San Andreas Fault at Jasper Ridge and Portola Valley, California, USA. The gas samples were analyzed for hydrogen, helium, carbon dioxide, light hydrocarbons, and fixed gas concentrations. Statistical data analysis was carried out to group samples, reveal their spatial distribution, and understand possible sources of the gases.High concentrations of hydrogen up to 20.3 ppmv and 17.3 ppmv occur in Jasper Ridge and Portola Valley, respectively, ~ 30-35 times greater than the atmospheric concentration. Most samples with high hydrogen concentrations fall on or near faults, suggesting an origin by serpentinization or geomechanical activation of catalytic sites in minerals, although a deep-seated primordial origin cannot be excluded. Elevated concentrations of carbon dioxide resulted from aerobic microbial degradation of organic matter and elevated concentrations of light hydrocarbons likely resulted from thermal cracking of organic matter.

This work re-interprets published SAM-EGA (Sample Analysis at Mars-Evolved Gas Analysis) geochemical data for twenty-four sediment cores sampled by the Curiosity rover. The samples were pyrolyzed at 35 degrees C/min in the range - 100-850 degrees C. The amount of methane generated from carbonaceous matter in the cores and its stable carbon isotope ratio (813C-CH4) in selected cuts within the full temperature range were determined by tunable laser spectrometry (TLS cut). Chemometric analysis of five independent variables for eighteen of the cores identifies four genetic families in which three endmembers explain most data variance. One endmember is contamination by silylating agent (MTBSTFA) introduced unintentionally from wet-chemistry cups during flight and/or after landing of the rover. Five subsamples from the Cumberland (CB) core show a linear relationship between 813C-CH4 and mean pyrolysis temperature (R2 = 0.77) within TLS cuts in the range 99-786 degrees C, which conforms with temperature-dependent kinetic theory. Based on dates of pyrolysis for the five CB samples, BSW (bisylylated water, a marker of MTBSTFA contamination) peaked on sol 281 and progressively decreased to sol 382. Linear regression of 813C-CH4 versus BSW concentration (R2 = 0.98) yields 813C-CH4 - -70%o for carbonaceous matter in uncontaminated CB core. Higher BSW yields systematically more negative 813C-CH4 to the most negative value of -133%o for CB1, which equates to an apparent fractionation of -98%o from bulk MTBSTFA (813C = -35%o) to CB1 methane. Previous workers suggested that 813C-CH4 from MTBSTFA could not be more than -5%o depleted compared to bulk MTBSTFA. However, their SAM-like laboratory pyrolysis experiments for analogs of MTBSTFA yield 813C-CH4 values that correspond only to gas trapped within the analyzed pyrolysis temperature cut (455-755 degrees C). Lower temperature TLS cuts for CB1 and CB2 (220-349 degrees C and 99-349 degrees C) trapped more 13C-depleted methane as reflected in their anomalous 813C-CH4 of -133 and - 115%o, respectively. In addition, pyrolysis of MTBFTSA byproducts, residual solvent, and internal standards with Martian minerals, perchlorates, and sorption or desorption on clays may contribute to more negative 813C-CH4 than expected from laboratory experiments that lack these components. It is not possible to determine bulk 813C or 813C-CH4 for the remaining two carbonaceous endmembers because of the effects of three factors: (1) Chemometric results by alternating least squares regression (ALS) define the relative contributions of endmembers based on five independent variables, not just 813C-CH4. (2) Samples from distinct locations and stratigraphic ages are subject to variations in 813C of deposited carbonaceous matter. (3) 813C-CH4 values for samples from different TLS cuts differ due to temperature-dependent kinetic fractionation.

Changes detected in the physicochemical conditions of the depositional palaeoenvironment of the Ponta Grossa Formation (Early-Middle Devonian), East Gondwana, were correlated with significant biotic crises that preceded the great Devonian extinction event (Frasnian-Famennian), culminating in the extinction of the Malvinokaffric fauna. The present study identified Zilchov, Daleje, Choteč, and Kačák biotic crisis events through geochemical analyses. Fifteen outcrop shale samples were analysed for the distributions of well-established geochemical parameters, such as those based on saturated and aromatic biomarkers and polycyclic aromatic hydrocarbons. Parameter results were correlated to polar compound distributions using atmospheric pressure photoionisation (APPI) coupled to Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR-MS) in positive ionisation mode. A decrease in the summation of n-alkanes, αβC30 hopane, and gammacerane concentrations was observed at the Pragian-Emsian interval, related to the Zilchov event and the first decline of the Malvinokaffric fauna. At the Late Emsian, a severe change in paleoenvironment depositional conditions was detected by the increase in αβ C30 hopane, tetrahydrophenanthrene and gammacerane concentrations, suggesting water column stratification. Moreover, Tricyclic Index values indicated a change to a more freshwater lacustrine environment, which was confirmed by the occurrence of n-alkyl cyclohexanes series. In addition, high percentages of O1 and N1 class compounds indicated that this interval was probably composed of a mixture of bacterial and terrigenous organic matter. These results indicated a large inflow of fresh and continental waters due to a regression related to the Daleje event and the second decline of the Malvinokaffric fauna. A significant decrease of the pristane/phytane ratio, summation of n-alkanes, αβ C30 hopane and gammacerane concentrations was observed, along with the absence of N1 compounds at the Emsian-Eifelian interval, representing a rapid transgression, corresponding to the Choteč event. At the Eifelian-Givetian interval, the detection of n-alkanes and biomarker low concentration values, low pristane/phytane values (anoxia), as well as the non-detection of N1 class compounds, indicated a great transgression related to the Kačák event and the disappearance of the Malvinokaffric fauna.

Source-related biomarker ratios and predicted families of fourteen oil/seep and artifact samples, Table 2 in "Ancient Olmec tar trade revealed by combined biomarker and chemometric analysis" by Carl J. Wendt and Kenneth E. Peters Table 2. Predicted families of fourteen oil/seep and artifact samples from the study area based on a two-tier SIMCA (soft independent modeling of class analogy) model constructed from the 97-sample training set in Table E1. The five samples from Rancho Orel, Salinas, Bat 2 Ogarrio, PO-22*, PO:23*, and SA:61A* have zero values for predicted family because they lack affinity to the families established by chemometric study of the training set. Asterisks identify archaeological artifacts. Plus signs ‘+’ in the description column identifies samples published previously (Wendt and Lu, 2006).

Resources such as tar, basalt, kaolin clay, and hematite are available in distinct areas near the ancient Olmec region of the southern Gulf Coast of Mexico. This uneven distribution of raw materials has led scholars to suggest that Olmec leaders controlled the sources of raw materials and regional trade, from which they derived economic and political power. The purpose of this study is to improve understanding of Olmec tar trade, which served as binder, sealant, and decoration. Our novel approach combines molecular archaeology based on the geochemistry of biomarkers (biodegradation-resistant molecular fossils) with chemometrics (multivariate statistics) to identify genetic relationships among crude oils, seep oils, modern applications, and archaeological artifacts excavated from ten Early and Middle Formative sites (1800-400 BCE) sites. Seven source-related biomarker ratios were calculated from peak heights on terpane and sterane mass chromatograms. We employed hierarchical cluster analysis dendrograms, which yield a simple view of genetic families of samples where cluster distance measures the degree of similarity. Our results illustrate patterns of Olmec commodity exchange and intra-regional interaction and the possibility of elite control of some tar procurement and distribution.

Fifteen crude oils from the Qaiyarah, Butmah, and Ain Zala fields were investigated using organic geochemistry to infer organic matter maturity, redox conditions of the depositional environment, and lithology of the corresponding source rocks. Carbon isotope compositions and sulfur contents were measured for all samples and saturated and aromatic biomarkers were analyzed by GC-MS. Low pristane/phytane (0.68-0.82) and high C35 S/C34S (1.03-1.66) and homohopane indices (0.14-0.24) in the oil samples indicate anoxic or euxinic conditions for the corresponding source rocks. In addition, sulfur content, C30 norhopane/C30 hopane, and C31 R/C30 hopane, Ts/Tm and C27 diasteranes/regular steranes values suggest carbonate source rocks with variable amounts of clays. These source rocks contain mainly type II-S kerogen. Moretane/hopane, hopane and sterane isomerization ratios suggest generation from early mature organic matter. Hierarchical cluster analysis identified three families charged from carbonate source rocks with variable amounts of clays and maturity. Oil-source rock correlation (based on published data) and age-related biomarkers suggest that these oils were generated from Jurassic source rocks (Sargelu, Naokelekan, and/or Chia Gara formations). Jurassic rocks in Ain Zala and Butmah area have low potential for hydrocarbon generation, therefore, the Ain Zala and Butmah oils were charged from Jurassic formations outside the Ain Zala area, but within the neighboring area northeast of Butmah and Ain Zala.

Recent exploration in the Nile Delta Basin has led to major oil and gas discoveries; however, source-reservoir relationships in the onshore part of the basin are still ambiguous. This work involves a comprehensive geochemical assessment of possible Oligocene-Pliocene source rocks, using TOC/Rock-Eval pyrolysis and gas chromatography-mass spectrometry. The aim is to investigate quantity, quality, thermal maturity, sources, and depositional paleoenvironment of the disseminated organic matter, and to correlate rock samples with hydro-carbons retrieved from the study area. Moreover, the chemical and isotopic compositions of gases were employed to examine origin, maturity, mixing and secondary alteration processes. Results reveal fair to good organic richness (TOC similar to 1 wt%) for the Oligocene-Pliocene rocks, with the highest TOC content from the Oligocene Tineh Formation. The kerogen is generally gas-prone Type-III and to a lesser extent Type-IV and Type-II/III. Molecular and biomarker results indicate mixed source facies with variable contributions from higher plants, algae, bacteria, and plankton, deposited under suboxic to anoxic nearshore marine or lacustrine depositional settings. Significant biomarkers include elevated C26/C25 tricyclic terpane ratios (0.82-3.62), low C31 homohopane (22R)/C30 hopane ratios (0.17-0.63), and low oleanane and gamma-cerane contents. Maturity-related biomarkers, Rock-Eval Tmax and vitrinite reflectance values are consistent and suggest immature to early mature rock samples. Molecular and isotopic compositions of mud gases indicate complex origins and mixing histories ranging from primary microbial to pure thermogenic, where thermogenic processes dominate the pre-Miocene intervals. Chemometric analysis of 18 source-related biomarker ratios for rock extracts revealed four genetic families. Hierarchical cluster analysis (HCA) of biomarker data for rock extracts and condensate oils from the onshore Nile Delta indicates no correlation between Miocene-Pliocene rocks and condensates or oils in the area. Therefore, pre-Miocene source rocks are suggested to be the most probable candidates for hydrocarbons in the onshore Nile Delta.

Exploration campaigns focusing on Paleozoic plays in the Egyptian north Western Desert Sallum and Faghur basins have been limited to date, and little has been done to investigate their hydrocarbon generation potential. A total of 284 shale, calcareous shale, coaly shale and siltstone side-wall core and cuttings samples, covering the rock succession that ranges from the Silurian Kohla Formation to the Turonian Abu Roash Formation were analyzed for source rock potential. In addition, eight reservoired Paleozoic-Mesozoic oil samples were geochemically analyzed. This paper systematically investigates (1) organic enrichment, hydrocarbon generation potential, and thermal maturity of Mesozoic as well as possible Paleozoic source rocks, and (2) composition and biomarker characteristics of crude oil samples in the study area from the far north Western Desert basins of Egypt. The Silurian Kohla and Basur and the Carboniferous Desouqy and Dhiffah siltstone and shale rock samples show overall poor and fair to good source rock potential for the Lower and Upper Cretaceous rock units, respectively. In contrast, high TOC (up to 4.83 wt%) and Rock-Eval S-2 (up to 6.57 mg HC/g rock) for the Devonian Zeitoun Formation samples indicates fair to very good source potential. The Middle Jurassic Khatatba Formation samples, compared with the Devonian Zeitoun Formation or other rock units in the stratigraphic column of the study area, have the highest TOC (30.1 wt%) and the highest S-2 (26.9 mg HC/g rock), indicating fair to excellent source rock potential. These high values of the Khatatba Formation are locally related to organic-rich coaly shales and calcareous shale intervals. The Rock-Eval results indicate an overall dominance of Type-III kerogen with strongly varying OI values. This highly gas-prone character for most samples was confirmed petrographically by abundant vitrinite phytoclasts and recycled organic matter. Coals and coaly shale facies from the Alam El Bueib and Khatatba formations that contain liptinitic materials may represent Type-III kerogens that are capable of generating gas with minor oil. Based on Rock-Eval Tmax and HI results, the Zeitoun and Khatatba samples range from early to peak oil window. This is consistent with the Ro measurements of the Paleozoic Zeitoun samples (0.65-1.02%) and the Middle Jurassic Khatatba samples (0.59-1.01%). The Faghur oils are light (35 degrees -46 degrees API gravity), belong to a single genetic family and are non-biodegraded based on wide-ranging n-alkanes. Abundant tricyclic diterpanes, C-24 tetracyclic terpane, C-27 Ts trisnorneohopane, diahopane, cyclohexanes, C-29 steranes and rearranged steranes and low to very low gammacerane and extended hopanes are common molecular signatures of the analyzed light oil and condensate samples. These findings indicate a relatively oxic fluvio-deltaic environment for the corresponding clay-rich coaly shale and calcareous shale source rocks that contain predominantly higher land-plants with negligible algal/bacterial organic materials. Based on saturated- and aromatic-maturity parameters, the analyzed oils were inherited from peak-late mature source rock.

The Nile Delta is a prolific hydrocarbon province in Egypt and the eastern Mediterranean region, particularly for gas resources. However, the origin of discovered hydrocarbons from the onshore Nile Delta has not been comprehensively studied. Fourteen condensates and 10 natural gas samples retrieved from Oligocene–Pliocene pay zones in the onshore northeast Nile Delta were studied for their molecular and isotopic composition to infer origin, source lithology, organic facies, depositional environment, thermal maturity, and reservoir secondary alteration. The isotopic compositions of the analyzed condensates indicate non-marine waxy oils. Results show that these condensates have high Pr/Ph ratios (1.86–6.46), abundant C19 and C20 tricyclic terpane contents relative to the C23 homologue, elevated oleananes, paucity of gammacerane, high hopane/sterane ratios, very low abundance of homohopanes, low dibenzothiophene/phenanthrene ratios and high C29/C27 sterane ratios. Clay-rich source rocks with abundant Type-III terrigenous organic materials deposited in an oxic fluvio-deltaic setting are suggested for these condensates. Light hydrocarbon (C7) compositions indicate that all investigated condensates, except the Allium-1 sample, suffered evaporative fractionation within their reservoirs. Chemometric analysis based on 14 biomarker and isotopic results suggests 3 genetic oil families for these condensates. These oil families have geochemical characteristics that indicate various contributions of terrigenous and marine organic matter and different levels of thermal maturity. The molecular and isotopic results indicate that the onshore Nile Delta natural gases are wet-thermogenic in origin with no signs of microbial biodegradation. These gases were generated by secondary cracking of associated oils derived from Type-III and Type-II/III or Type-II kerogen. The condensate and associated gas samples from Oligocene pay zones have different geochemical signatures than those from Miocene reservoirs, suggesting derivation from different source rocks with variable levels of thermal maturity or the presence of multiple charge systems from a common source in the onshore Nile Delta.

Oil samples from the Halfaya, Noor, and Amara oilfields were geochemically characterized to determine their origin, type of organic matter, and the depositional environment conditions of the correlative source rocks. Detailed saturated and aromatic biomarkers from nine oil samples were analyzed using gas chromatography and gas chromatography-mass spectrometry, and measurement of sulfur content and stable carbon isotopes. Saturated hydrocarbons in the oil samples are low, whereas polar fractions are relatively high. Saturated (terpane and sterane) and aromatic biomarker ratios suggest that these oil samples were generated mainly from early to mid-mature carbonate source rocks. The anoxic marine depositional environment of the source rocks is reflected by the high C35S/C34S hopane and low Pr/Ph ratios. Hierarchical cluster analysis (HCA) identifies two oil families. These oil families may have originated from the same source rock but with different organofacies. Regular sterane distributions differ from those for oils from the southern oilfields (Majnoon, Nasiriah, West Qurna, North Rumaila, Luhais, Abu Gharab, Faka, Buzergan). Biomarker ratios indicate that the present study oils are slightly more mature than southern oils and their source rock depositional environment was more reducing (anoxic). Based on comparison with previously published data, the most likely source rocks for the present study oils include the Sulaiy, Yamama, and Zubair formations.

The most commonly used parameter for thermal maturity calibration in basin modelling is mean random vitrinite reflectance (R-o). However, R-o suppression has been noted in samples containing a high proportion of liptinite macerals. This phenomenon has been demonstrated empirically using hydrous pyrolysis of artificial source rock containing various proportions of thermally immature Wyodak-Anderson coal and liptinite-rich kerogen from the Parachute Creek Member of the Green River Formation. Analysis of samples pyrolyzed at 330 degrees C for 72 h demonstrates that R-o values of both vitrinite and solid bitumen are suppressed in rocks containing liptinite-rich kerogen. Raman and micro-Fourier transform infrared (mu-FTIR) analyses were performed to investigate the mechanisms of suppression. Raman maturity proxies show decreased aromaticity in samples with suppressed Ro, particularly in solid bitumen, with aromaticity decreasing as the proportion of liptinite increases. The mu-FTIR proxy for aliphatic chain length and/or branching ratio is static in solid bitumen, yet increases slightly in vitrinite as the liptinite proportion increases. These spectroscopic results suggest slightly different suppression mechanisms for vitrinite and solid bitumen, with reduced C-C bond cleavage and marginally reduced aromaticity in vitrinite with suppressed R-o, and strongly reduced aromaticity and C-C bond cleavage in solid bitumen with suppressed R-o. These results support the hypothesis that the generation of free radicals during maturation slows aromatization and highlight the disadvantages of using solid bitumen R-o for maturity calibration in liptinite-rich samples. Furthermore, our results indicate that use of Raman data obtained from liptinite-rich samples may also result in suppressed maturity indicators, particularly if the macerals are not identified prior to analysis.

Experiments were conducted to distinguish oil cracking in reservoir rock versus source rock. Oil and source rock samples were heated in pressure vessels at 380 degrees C for 72 h, which resulted in oil cracking to gas and pyrobitumen with some residual liquid. The oil samples were heated with different minerals (fine-grained quartz, calcium carbonate, montmorillonite, kaolinite and illite) employing different ratios of the oil to the mineral in each case. Heating oil with quartz or calcium carbonate was used to simulate oil cracking in reservoirs, while heating oil with clay minerals was used to simulate oil cracking within source rocks. Based on the experiments, oil cracking in reservoirs versus source rocks can be differentiated by relative concentrations of the prominent C7 hydrocarbons: n-heptane, methylcyclohexane and methylbenzene (toluene) in the liquid products. The light hydrocarbon distribution in the final cracking products is affected by the "matrix effect" from clay minerals and the surrounding medium in reservoirs and source rocks during oil cracking. No relationship between the types of marine source rock or total organic content (TOC) and the distribution of light liquid hydrocarbons generated by catalysis on clay minerals at high temperature was observed. Future studies are needed to evaluate different types of source rock (e.g., terrigenous versus marine, clastic versus calcareous), and the relationship between light liquid hydrocarbon yield and the quantity of each clay mineral.

An important step for any frontier basin source rock survey is to understand the natural variability of geochemical characteristics within the source intervals. No previous studies addressed the molecular characteristics of organic matter or the source rock potential in the west and northwest onshore/offshore portion of the Nile Delta province. For this reason, the current work used geochemical proxies, including Rock-Eval/TOC screening analyses, gas chromatography-mass spectrometry, and metastable reaction monitoring mass spectrometry to examine the type and origin of the disseminated organic matter, thermal maturity, and depositional environments of the Miocene-Pliocene sediments in this basin. Results show fair-very good organic content for the Miocene Sidi Salem and Abu Madi rock samples compared to the Pliocene Kafr El Sheikh and El Wastani samples that generally show low TOC with fair-good organic content. The low organic content recoded in the Pliocene rocks may be due to high rates of sedimentation associated with elastic dilution and microbial degradation, typical of deltaic environments. In general, kerogen in the samples has high proportions of gas or non-generating and recycled organic materials and is dominantly of fluvial or deltaic origin. The analyzed source rocks exhibit a wide range of organic matter quality varying from Type-III, Type-II/III, to Type-IV kerogens. The molecular findings suggest mixed-source input from planktonic-bacterial and land plants with significant algal contributions to the source rock facies. This is based on high C-30 24-n-propylcholestanes, C(27 )cholestanes and C-29 stigmastanes, moderate tetracyclic polyprenoid (TPP) ratios, and low oleanane and gammacerane. The most striking biomarkers are high bicadinane and 24-norcholestane ratios. Local differences related to facies variation in the source depositional environment result in significant variations in biomarker characteristics. Pyrolysis T-max sterane isomerizations %20S and %beta beta, moretane/hopane ratios, and C-32 homohopane %22S suggest immature to maturity near the beginning of the oil window. Five genetic families were identified among the extract samples using hierarchical cluster analysis (HCA) and principal component analysis (PCA) based on 15 source-related biomarker ratios. Some of these families are questionable because of low TOC, significant differences in maturity between the extracts and condensates, and possible contamination by diesel additive. However, five rocks from the Miocene Sidi Salem Formation contain elevated TOC (1.22-2.25 wt%) and HI (366-458 mg HC/g TOC) and the extracts show no evidence of significant contamination in the biomarker range of molecular weight and good correlation with four WDDM-14 (2739, 2854, 2804, and 2870 m) oils in the offshore Rosetta and Abu Qir oilfields.

Despite documented pitfalls, many geoscientists continue to publish problematic oil–oil correlations based on compound ratios determined from “dead oil” that lacks volatiles. Mixtures of petroleum from more than one source rock pose issues for assigning genetic affinity, proportions of contributing end members, and predicted gas–liquid ratios. Compound ratios mix in nonlinear fashion for end members like black oil versus gas condensate. Correlations and allocations of end-member contributions apply only to the molecular-weight range of analyzed compounds. In this study, biomarker concentrations for four pairs of end-member fluids with gas–liquid ratios from 100 to 50,000 SCF/bbl were mathematically combined to yield four series of binary mixtures in 5% increments. The purpose was to evaluate the reliability of chemometric analyses to assign genetic affinities and to deconvolute the relative contributions of end members to each mixture. Hierarchical cluster analysis of biomarker ratios shows that mixtures having major contributions of gas condensate cluster with those dominated by input from the oil-prone end member, resulting in incorrect genetic classifications. Mixture deconvolution by alternating least squares regression of ratios can seriously underestimate the contribution of the gas condensate or higher gas–liquid ratio oil source, as can alternating least squares regression of concentrations on a whole-liquid basis. A biased view of the contributions from source rocks to mixtures hinders understanding of petroleum systems and distorts expectations of fluid phase and bulk properties. However, alternating least squares regression of compound concentrations on a whole-fluid basis correctly assigns the relative contributions of end members because it includes the gas fraction (C1–C5) and the liquids (C6+).

An oil–oil and oil–source rock correlation study was carried out using chemometric methods applied to geochemical data for 123 Upper Cretaceous—Lower Miocene putative source rock and 46 crude oil samples from the Gulf of Suez Rift basin. The Gulf of Suez has many organic-rich intervals. The pre-rift source units, such as the Brown Limestone and Thebes formations, contain very good-to-excellent organic content, whereas the Miocene rocks are rated fair to good. HI and Tmax pyrolysis data indicate variable kerogen type and maturation histories where most of the analyzed samples occur along the Type II and Type II/III kerogen pathways from immature to the main stage of oil window with %Ro < 0.9. Carbon isotope ratios’ biomarker data for the bitumen samples indicate predominantly anoxic source rock depositional conditions with substantial algal/bacterial marine and a minor terrigenous organic matter. The Gulf of Suez oils exhibit a wide range of chemical composition from heavy-to-medium gravity and moderate-to-high sulfur content. These oils originated from carbonate/marl source rocks rich in lipids from phytoplankton/benthic algae and bacteria with less contribution of terrigenous organic debris, deposited under anoxic conditions with different thermal maturity histories equivalent to at least the early oil window. Chemometrics using 16 source-related biomarker and isotope ratios identifies six genetic families in the Gulf of Suez. The oil families share common characteristics where the precursor organic matter was deposited in a restricted marine environment with limited land-derived organic matter. The major factor that greatly modifies oil composition in the Gulf of Suez is thermal maturation. However, migration history and spatial and temporal organofacies’ variations of the presumed source rocks are also important. The overall geochemical similarity of the Gulf of Suez oils confirms the mixed nature of these fluids and suggests that no single source rock horizon is likely to have sourced the oil in this promising province. Based on oil–source correlation data and a decision tree chemometric model, the Brown Limestone, Esna, Thebes, and Nukhul formations are the effective source rocks for oil families III, IV, and V, whereas none of the source rock extracts has been assigned for Family I or VI oils.

Although recent gas and condensate discoveries have been achieved in the deep ultramarine Nile Delta Basin of northern Egypt, the genetic origin and formation mechanisms of these hydrocarbons remain unclear. Twenty condensate and 34 natural gas samples from Miocene-Pliocene sandstone reservoirs in the northwest Nile Delta offshore Egypt were analyzed to infer their origin, degree of thermal maturity, and extent of alteration. Based on source-related biomarkers, the condensate samples were interpreted to have originated from clayrich non-marine source rocks, based on high Pr/Ph, high Ts/Tm, low or absent C-30 n-propylcholestanes and high hopane/sterane ratios. The environment of deposition of the source rock is expected to be proximal and likely received high influx of terrigenous-dominated organic matter. Chemometrics of 12 source-related biomarker and isotopic ratios identify six genetic families. Geochemical characterization of the families shows that they are broadly similar but differ in terms of source-rock depositional paleoenvironment, organic matter precursors, thermal maturation and microbial degradation. Age and maturity biomarker fingerprints show that these hydrocarbons were generated from at least two active pods of Upper Cretaceous and Oligocene or younger source rocks, as confirmed by high oleananes, bicadinanes, and high C-26 24-norcholestane indices. Gas chemical and isotopic compositions of propane, ethane, and methane reveal a mixed microbial and thermogenic origin, where the relative proportion of biogenic component reaches up to similar to 70%. The thermogenic gas was generated from mixed Type-II/III or Type-II kerogen with a wide range of maturity between 1.0% and 1.5% R-o from primary kerogen cracking to the late stage of gas cracking. Heavier C2+ hydrocarbon isotope signatures and bulk compositions indicate that the shallower gas accumulations are severely biodegraded, unlike that in the deep hydrocarbon reservoirs. The co-occurrence of unaltered gas with biodegraded condensates may indicate different microbial communities involved in these processes, or more likely, the gas arrived in the reservoir as a second charge after biodegradation of the original condensate.

The purpose of this work is to identify genetic affinities among 48 crude oil samples from the onshore and offshore Santa Maria basins. A total of 21 source-related biomarker and stable carbon isotope ratios among the samples were assessed to assure that they were unaffected by secondary processes. Chemometric analysis of these data identifies six oil families with map and stratigraphic distributions that reflect organofacies variations within the Miocene Monterey Formation source rock. The data comprise a training set that was used to create a chemometric decision tree to classify newly collected oil samples. Three onshore families originated from two synclines, which may contain one or more pods of thermally mature source rock. Multiple biomarker parameters indicate that the six oil families achieved early oil window maturity in the range of 0.6%–0.7% equivalent vitrinite reflectance. The offshore oil samples consist of one family from Point Pedernales field and two families from the “B” prospect. Geochemical characteristics of these families indicate origins under differing water column and sediment oxicity and carbonate versus siliceous and detrital input in ‘carbonate,’ ‘marl,’ and ‘shale’ organofacies like those in the lower calcareous–siliceous, carbonaceous marl, and clayey–siliceous members of the Monterey Formation elsewhere in coastal California. The corresponding lithofacies and organofacies appear to be linked to the early–middle Miocene climate optimum and subsequent paleoclimatic cooling after circa 14 Ma, a systematic up-section increase in the stable carbon isotope composition of related oil samples, decreased preservation of calcium carbonate shells from planktic foraminifera and coccoliths, and increased preservation of clay-sized siliceous shells of diatoms and radiolarians. The results show that organofacies within the Monterey source rock are responsible for many of the geochemical differences between the oil families. This paleoclimate–organofacies model for crude oil from the Monterey Formation can be used to enhance future exploration efforts in many areas of coastal California.