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The interaction between various components of shale and CO2 is interesting since it alters pore structures that are the governing factor in different projects. In this study, samples from the Upper...

Biogenic gas shales, predominantly microbial in origin, form an important class of organic-rich shale reservoirs with a significant economic potential. Yet large gaps remain in the understanding of their gas generation, storage, and transport mechanisms, as previous studies have been largely focused on mature thermogenic shale reservoirs. In this study, the pore structure of 18 Antrim Shale samples was characterized using gas adsorption (CO2 and N2). The results show that most of the Antrim Shale samples are rich in organic matter content (0.58 wt.% to 14.15 wt.%), with highest values found in the Lachine and Norwood members. Samples from the Paxton Member, characterized by lower organic content, have smaller micropore surface area and micropore volume but larger meso-macro pore surface area and volume. The deconvolution results of the pore size distribution from the N2 adsorption indicate that all of the tested Antrim Shale samples have similar pore groups. Organic matter in the Antrim Shale hosts micro pores instead of meso-macro pores, while clay minerals host both micro and meso-macro pores. Mineral-related pores play a primary role in the total porosity. The biogenic Antrim Shale, therefore, has different pore structures from other well-studied thermogenic gas shales worldwide.

Pore structure of unconventional reservoir is fundamental for understanding hydrocarbon storage, fluid transport, and geomechanics. The pore structure of shale gas reservoirs has been studied exten...

During the past decades, exploration activities carried out in the Western Desert of Egypt by several oil companies revealed the oversimplified approach to the study of sedimentary basins in this region. The current study evaluates and discusses the palynology and palynofacies of the clastic succession of the Kharita Formation (Albian) in one of the most petroliferous, deep seated, fault controlled basins in the Western Desert of Egypt, the Abu Gharadig Basin. Although the focus is on the palynofacies association, the hydrocarbon potential of the Kharita Formation will also be addressed by means of organic petrology and Rock-Eval pyrolysis. Marine Cretaceous source rocks have generated substantial quantities of oil and gas in the Abu Gharadig rift Basin. Moreover, Abu Gharadig Basin is characterized by containing not only oil/gas generating source rocks but also reservoir rocks with appreciable porosities and permeabilities. Palynological, TOC/Rock-Eval pyrolysis, and vitrinite reflectance (VRo%) data from 26 cuttings samples recovered from the Kharita Formation in the BED 2-1× well, are presented. The palynological age dating (AL-2 Palynozone) confirmed early to middle Albian age based on the first downhole appearance of the marker Concavisimisporites punctatus. The optical and visual characterization of the palynofacies associations showed two distinct palynofacies associations that alternated with each other. Kerogen type III to III/II was recorded based on the dominance of phytoclasts and opaque organics. Some intervals showed a slight dominance of amorphous organic matter (AOM). Thermal Alteration Index (TAI) values of 2+/3-measured on the psilate trilete spores, in combination with vitrinite reflectance (VRo) values in the range from 0.51 to 0.62%, and the yellow to dull-yellow colors of the liptinite macerals exhibited under UV light excitation indicate immature to the early stage of the oil window. Tmax values from Rock-Eval pyrolysis range from 426 to 438 °C also confirm the low maturity of the organic matter. Thin coal stringers were recorded within the Kharita Formation having slightly higher VRo,ran values (0.64 to 0.76%), which is possibly the result of differences in mineral matrix variations within the Kharita Formation. Based on the low TOC (avg. 0.71 wt%), S2 (avg. 0.97 mg HC/g rock), and HI (avg. 149 mg HC/g TOC) values from pyrolysis, the hydrocarbon potential of the Kharita Formation in the studied well is considered to be low.

It is well known that the NMR relaxation time T2 is proportional to the molecular mobility of water or hydrocarbons in rocks. In unconventional tight rocks, water and hydrocarbons are trapped in small pores of nanometer sizes, and their molecular mobility is severely restricted, causing the NMR T2 to be much shorter than that of conventional cases where pore sizes are in micrometer ranges. There are demands for advanced NMR techniques to study those solid-like bound hydrocarbons. In the meantime, it is of great interest for petrophysicists and geochemists to understand kerogen models in order to determine thermal maturity and hydrocarbon potential of organic-rich source rocks, and always attractive to have practical techniques that are nondestructive and less time consuming. In this study, a series of NMR 1D and 2D experiments have been performed on various types of source rocks with emphasis on short NMR T2 components, from sub-milliseconds down to a few microseconds, which are associated with kerogen, heavy hydrocarbons, and small hydrocarbon molecules bound in nanopores. The results show that the NMR CPMG pulse sequence used for the T2 data acquisition is (1) not capable of detecting and measuring the very rigid solid component of the T2 shorter than 30 microseconds, which is thought from kerogen, and (2) uncertain for the NMR components with T2 between 30 microseconds and 0.1 ms, which is dependent on the inter-echo spacing time (TE). Instead, the solid echo-pulse sequence was used to acquire the early time NMR signals that represent rigid solid matters, such as kerogen, in rock samples that have short relaxation times of less than 20 microseconds. The NMR solid echo signals were fitted into a composition of a Gaussian plus exponential functions to better describe NMR responses of source rocks with the shortest relaxation time of a few microseconds. The Gaussian component in the NMR signal is the measure of rigid solids associated with kerogen in the source rock. Model rock samples of thermally immature outcrops of the Upper Jurassic Kimmeridge Clay Formation in the UK and the Green River Shale Formation in the USA were used for comparison studies between the low field solid NMR techniques and geochemical analytical methods. The thermal maturities of the samples were artificially altered through the hydrous pyrolysis method at selected temperatures. The comparison results show that the amplitude of the Gaussian component measurement by NMR strongly correlated with the S2 of pyrolysis. The NMR relaxation times of the solid portion are directly proportional to the thermal maturity determined by organic petrography. This study concludes that the nondestructive solid NMR method provides an alternative and rapid way to study solid organic matters. The combined techniques enable us to further study kerogen models and hydrocarbon-generating potentials in organic-rich source rocks.

Summary A new potential source rock formation was discovered in Ionian Zone, Epirus region, western Greece and its organic petrographic and organic geochemical characteristics were investigated. The formation lies between the overlying lower Liassic “Pantokrator Limestones” and the underlying Rhaetian “Pantokrator Dolomites”. It consists of alternating organic-rich black shale and less organic-rich gray dolomite/dolomitic sandstone beds. The organic geochemical results suggest high amounts (up to 35,56 wt.% TOC) of Type I and II/IIS organic matter, with a Hydrogen Index up to 790 mg HC/g rock and a high remaining generation potential (S2) of 237,4 mg HC/g rock. Based on the mean Tmax of 422⁰C and on %VRo-eq from solid bitumens, formation hasn’t entered the oil window in this part of the basin. Nevertheless, presence of Type IIS kerogen in some samples, indicate that certain intervals of the formation may already have entered oil window and produced liquid hydrocarbons. Relatively high clastic input may be indicative of a climatic shift towards seasonably controlled wetter conditions, as it is inferred from adjacent areas. This study suggests that the stratigraphic position and the geochemical characteristics are comparable to intervals in Albania and Italy, possibly indicating a source rock interval with regional significance.

The Bakken Formation is a major unconventional shale play in North America, which lacks an independent calibration for accurately correlate thermal maturity from programmed pyrolysis (via temperature of maximum pyrolysis yield, Tmax) with optical methods (e.g., bitumen reflectance). In the present study, several samples from the upper and lower members of the Bakken Formation in North Dakota were analyzed by detailed organic petrography, bitumen reflectance, and Rock-Eval 6 pyrolysis. Organic petrography showed that the organic matter consists of various types of bitumen, amorphous matrix bituminite, liptodetrinite, acanthomorphic acritarch, marine alginite, granular micrinite, and inertinite macerals. Fluorescence color under UV light of macerals from the liptinite group was used to confirm the thermal maturity level. Due to the scarcity/absence of primary vitrinite, RO measurements on solid bitumen particles were converted to equivalent vitrinite reflectance (VRO-Eq) using a published correlation equation from the coeval New Albany Shale. Overall, geochemical analysis from Rock-Eval pyrolysis reveals almost similar trends for the upper and lower members, which allowed proposing a single correlation for VRO-Eq to Tmax for the Bakken Shale. Comparing the observed relationship for the Bakken Shale with the previously established models for the Devonian Duvernay Shale (Canada) and the Mississippian Barnett Shale (United States) shows discrepancies. Results confirmed the necessity of developing a specific equation for the Bakken Shale members to relate vitrinite and solid bitumen reflectance data to Tmax from Rock-Eval pyrolysis. Furthermore, the outcome of this study indicated that linear trends cannot accurately represent the relationship between these two parameters, considering the kerogen kinetics and non-linear relationship between transformation ratio (TR) and Tmax. Therefore, a polynomial correlation, a better fit to the data, was proposed to more accurately represent the nature of this relationship.

Lacustrine oil shale and shale samples of the Tournaisian-age Albert Formation in New Brunswick, Canada, taken from six locations, were analyzed by organic petrology using reflected white and fluorescence light microscopy and by Rock-Eval pyrolysis to determine their depositional environment and hydrocarbon generating potential. Calcium, Th, and Ca contents of the samples were also determined using ICPMS. The results were compared to the Big Marsh lacustrine oil shale of Carboniferous age in Nova Scotia. Organic matter consists mostly of filamentous alginite, bacterial remains, and matrix bituminite, which fluoresce green to dark-yellow. Organic matter was deposited in a lake basin. The regular layering of algal remains and wrapping around mineral particles indicate deposition in a low energy setting below wave base, which resulted in the stratification of the organic matter and the enclosing mineral matrix. There are also fluorescing to non-fluorescing bitumens present in parts of the Albert oil shale. The bitumens were incorporated as a result of hydrocarbon migration during deposition of the oil shales (the two are considered to be syn-sedimentary) because the bitumens are part of the regular rock layering and the fact that the organic matter is wrapped around mineral grains. The bitumens in the Albert oil shales consist of fluorescing wurtzilite and non-fluorescing albertite. The Albert oil shales have lower input of terrestrial sediments containing Th and are carbonate-rich. The variation of Th/U ratio and TOC (wt%) indicates that the Albert oil shales have different mineralogy than those from the Big Marsh ones. There are two types of carbonates particles in the Albert oil shale; a) syngenetic angular particles, which are suspended in the organic matter but may also occur as micrite, and b) rounded to angular and possibly transported particles containing oil inclusions. As a result, variations in Th/U and calcium divided the oil shales into: a low-calcium lacustrine type (which includes the Big Marsh oil shale); the Albert oil shale and shale deposited far from the Albert Mine; and few samples from a deposit close to the Albert Mine that have high calcium content and some of them contained oil inclusions. The higher TOC of samples collected from the bitumen mining area in the Albert Mine is related to bitumen impregnation due to hydrocarbon migration. Variation of HI (mg HC/g/TOC) and authigenic uranium in the Albert oil shale indicates that depositional environment was more anoxic than most of the oil shales in the Big Marsh deposit. Rock-Eval pyrolysis data and accompanying organic petrology analysis indicate that the samples are mostly immature to marginally mature as indicated by %Ro, ran of 0.60–0.68 and variation in the fluorescence Red/Green and Blue/Green and Blue (R/G, B/G, B) quotients. Variations in maturity indicators (such as HI and Tmax) are caused by other factors, such as quantity of organic matter in the samples. The Hydrogen Index (HI) vs. Tmax plot of the oil shales displays a wide range of HI within a narrow Tmax range of 438–442 °C indicating immature to marginally mature Type I kerogen. There is a slight trend of increasing Tmax into the oil window with increasing HI, likely due to the extreme mass of hydrocarbons in these samples, which requires higher energy to breakdown, rather than burial-related thermal maturity. Maturity of the Albert oil shale increases from east to west within the study area as indicated by the westward increase of all three fluorescent quotients of both filamentous algae and matrix bituminite and in the %Ro. The reflectance of the Albert oil shales, measured on vitrinite, is mostly suppressed compared to the nearby Mapleton organic-lean shale in New Brunswick. There is also a correlation between HI and %Ro, ran in the oil shale samples studied; the higher is the HI, the lower is the %Ro. The majority of the oil shale samples have a very high potential for hydrocarbon extraction using the ex-situ methodology (at 30 L/t) and the upper 20% of the samples have the potential for in-situ extraction (at 60 L/t).

Understanding organic matter properties in terms of maturity and production potential are crucial for the initial assessment of unconventional plays. This is important since the amount of hydrocarbon that can be generated is a function of organic matter type and content in the formation and its thermal maturity. The complexity of shale plays in terms of constituent components has demonstrated that new analytical methods should be acquired to better understand hydrocarbon generation processes. In this study, a few samples from the upper and lower members of the Bakken Formation in the USA were selected from different depths and maturity levels. The samples were analyzed by a high frequency (22 MHz) nuclear magnetic resonance (NMR relaxometry) equipment, followed by Rock-Eval pyrolysis (using the Basic/Bulk-Rock method for all samples and a multi-heating rate method, MHR, for the two least mature samples) and bitumen reflectance evaluations. Results showed NMR can detect different hydrogen populations within the samples and distinguish among phases, such as solid organic matter, hydrocarbons (mobile oil), and water by T1-T2 mapping. We were also able to relate different identified areas on NMR T1-T2 maps to geochemical parameters of the organic matter obtained from Rock-Eval pyrolysis (such as S1, S2, and HI) and with thermal maturity (vitrinite reflectance-equivalent).

Organic-rich shale, which is a heterogeneous material, has been studied extensively from various perspectives. Among all the components that constitute shale, organic matter is less known in regards to its mechanical properties. Since organic matter is relatively the softer part compared to inorganic minerals, high concentrations of it can have a significant impact on bulk mechanical properties of the rock, which can affect field operations such as hydraulic fracturing. In this study, four shale samples from the Bakken Formation in Williston Basin, North Dakota, were examined by a combination of experimental methods including X-ray diffraction (XRD), Rock-Eval pyrolysis, optical and scanning electron microscopy (SEM) along with atomic force microscope (AFM). PeakForce Quantitative Nano-mechanical Mapping mode in AFM was used particularly, to map the modulus of organic matter in nano-scale. XRD analysis showed that quartz and clays are the main constituent minerals in the shale samples. Geochemical results showed that all samples are extremely organic-rich, and the organic matter is mostly type II, varying from thermally immature to oil generation window. Elastic properties test results demonstrated that surface topographic features including pores, microfractures and grain boundaries would have a negative impact on AFM data, and a data filtering procedure was conducted on AFM data to get rid of wrong values. The elastic modulus of identified organic matter (bitumen and micrinite) was measured in the range of 7–23 GPa with a significant heterogeneity in a single studied organic particle and dependent upon the type of organic particle.

The impact of a 120 cm thick dike on dispersed organic matter in the Triassic Marry Harbour (MH) bituminous marl in the Raanes Peninsula, Ellesmere Island, Arctic Canada, was studied using reflected light microscopy and Rock-Eval pyrolysis. Results were compared to a coal seam of similar maturity that was thermally altered by an igneous intrusion. The MH bituminous marl is mature and within the oil window (Ro = 0.94%), whereas the coal is high-volatile B bituminous rank (Ro = 0.80%). Thermal alteration impacted differently the organic-rich marl than the coal seam. Most of the heat generated by the intrusive emplacement in contact with coal is spent transforming coal to coke in the plastic layer/zone, similar to the process that coal undergoes in industrial coking operations. In contrast, the thermal alteration of sedimentary rocks occurs over longer distances as a result of the absence of a plastic layer/zone. The impact zone of the 120 cm thick igneous intrusion was greater in the MH bituminous marl, which became thermally altered (Ro = 2.34%) at 190 cm from the contact with the dike. On the contrary, the coal became thermally altered (%Ro = 5.0%) by a 240 cm alkali-basalt intrusion (twice the thickness of the MH dike) and its impact zone was only 65 cm. Heat and hot volatile matter produced by the thermal decomposition of organic matter and minerals (carbonate, dehydration of clay minerals) in contact with the igneous intrusion body is transferred through the sedimentary rock matrix by convection through fractures. This transformation is evident by the occurrence of the pyrolytic carbon at various distances in the fractured MH marl from contact. The hydrogen index (HI) shows a similar trend to that of the remaining source potential (S2). Both parameters decrease systematically toward the dike, and go through a minimum at 20 cm from the dike contact, as the indigenous organic matter is converted to hydrocarbons or devolatilized. At the dike contact, both S2 and HI have higher values. These trends are similar to those of the volatile elements H and Cl in the intruded coal seam. The free hydrocarbons (S1) showed a slightly different trend than S2 and HI. It increased initially from 300 cm and reached a maximum at about 190 cm from the dike contact before decreasing continually and reaching a minimum at 20 cm from the contact. At the dike contact, the S1 increased slightly, similar to the HI and S2. The presence of oil droplets trapped in carbonate concretions, in combination with the highest value of oil expelled from the source rock (based on S1/TOC) at distance of 190 cm from dike, is an indication of the influence of contact metamorphism on oil generation locally. Furthermore, it indicates that intrusion of igneous dikes into the bituminous MH marl resulted in an increase of organic matter maturation locally and in hydrocarbon generation.

Diamondoids are a class of cage-like hydrocarbons that are structurally similar to small pieces of diamonds. Their formation from polycyclic precursors parallels their dynamic stability. Diamondoids occur naturally in virtually every oil and condensate as well as in source-rock extracts. Their ubiquitous nature in oils and extracts of any thermal maturity level, along with their proven stability with increasing maturity, makes them useful as thermal maturity proxies past peak oil window and in the identification of mixtures of low- and high-maturity fluids. Two relationships in particular, methyldiamantane index (or MDI) and 3- + 4-methyldiamantane concentration vs. Stigmastane [5α, 14α, 17α(H)-24-ethylcholestane 20R C29 sterane] concentration, are repeatedly used to establish thermal maturity relationships between oils and between oils and extracts and to identify mixtures of fluids with different thermal maturities. The present comparative study shows how methyldiamantane proxies from West Texas oils and extracts (sourced from the Woodford Shale) and in oil samples from northern South America (Colombia) and the Middle East show overall a very good agreement with classic maturity proxies, such as Tmax values from Rock-Eval pyrolysis and vitrinite reflectance (Vro). However, caution is advised when using methyldiamondoid-derived proxies in the presence of drilling additives and contaminants (e.g., oil-based mud or OBM) and of oils and extracts that have experienced biodegradation. The latter is probably a highly unrecognized issue when using methyldiamondoids, which can result in erroneous interpretations of thermal maturity and mixing. Based on the results of this study we recommend the necessity of a holistic, multi-proxy approach, based on the integration of geochemical screening, organic petrography, and molecular geochemistry techniques as the best possible solution when dealing with such geochemical conundrums.

Organic-rich shales are highly heterogeneous due to the presence of a variety of constituent components. Among them, organic matter is poorly known in terms of mechanical properties due to the lack of high-resolution analytical equipment to isolate organic matter in-situ for mechanical testing. In this study, we proposed a new method to link morphology and geochemical properties of organic matter to its mechanical characteristics at the nanoscale. Kerogen type and thermal maturity, along with mineralogy were evaluated by Rock- Eval 6 pyrolysis/Total Organic Carbon (TOC) analysis and X-ray Diffraction (XRD) analysis. Then, the atomic force microscopy PeakForce Quantitative Nano-mechanical Mapping (AFM PeakForce QNM) mode was employed and coupled with optical and electron microscopy, to first visualize and then quantify the elastic properties of organic components in three different samples from the Bakken Formation. Hebamorphinite matrix bituminite and solid bitumen were identified as the main organic constituent, along with oil-prone marine kerogen type II (alginite and acritarch) and also a bacterial-derived granular micrinite-like maceral. Based on Tmax and vitrinite Ro values (or VRo-Eq from Bitumen Ro), thermal maturity of the samples ranged from immature to mature (past peak oil window). The average value of Young's modulus for organic matter was measured in the range of 2.91–11.77 GPa. It was also found that organic matter becomes stiffer with increased thermal maturity. This study exhibits a great potential, as a novel method, for in-situ analysis of mechanical properties of organic matter in shale reservoirs at a fine scale.

Pores that exist within the organic matter can affect the total pore system of bulk shale samples and, as a result, need to be studied and analyzed carefully. In this study, samples from the Bakken Formation, in conjunction with the kerogen that was isolated from them, were studied and compared through a set of analytical techniques: X-ray diffraction (XRD), Rock-Eval pyrolysis, Fourier Transform infrared spectroscopy (FTIR), and gas adsorption (CO2 and N2). The results can be summarized as follows: 1) quartz and clays are two major minerals in the Bakken samples; 2) the samples have rich organic matter content with TOC greater than 10 wt%; 3) kerogen is marine type II; 4) gas adsorption showed that isolated kerogen compared to the bulk sample has larger micropore volume and surface area, meso- and macropore volume, and Brunauer–Emmett–Teller (BET) surface area; 5) deconvolution of pore size distribution (PSD) curves demonstrated that pores in the isolated kerogen could be separated into five distinct clusters, whereas bulk shale samples exhibited one additional pore cluster with an average pore size of 4 nm hosted in the minerals. The comparison of PSD curves obtained from isolated kerogen and bulk shale samples proved that most of the micropores in the shale are hosted within the organic matter while the mesopores with a size ranging between 2 and 10 nm are mainly hosted by minerals. The overall results demonstrated that organic matter-hosted pores make a significant contribution to the total porosity of the Bakken shale samples.

This paper discusses the hydrocarbon potential of the Jurassic succession in a mature basin in Egypt as an important element of a larger petroleum system study. Prior to any organic petrographic and organic geochemical analyses, a palynological age dating of the originally undifferentiated Jurassic sequence was carried out to identify different formations under investigation. This was based on key bioevents of some recovered dinoflagellate cysts and the identified lithology. Palynological, TOC/Rock Eval pyrolysis (including modified Rock-Eval methods), and vitrinite reflectance (VRo%) data from a total of 14 samples taken from the uppermost lower-upper Jurassic sequence represented by the Wadi Natrun (Toarcian-Aalenian), Khatatba (late Bathonian-Callovian), and Masajid (Oxfordian) formations in the Abu Tunis-1 × well, are presented. In addition, two samples from the Abu Tunis-1 × well and the proximal (~ 32 km to the east) Siqueifa-1 × well, having the highest remaining hydrocarbon potential (S2 yields), were analyzed and their results were compared using modified pyrolysis programs. Although the data showed a good correlation between the TAI of the palynomorph assemblage, vitrinite reflectance, and Tmax from Rock-Eval pyrolysis in the shallower intervals, the correlation between VRo and Tmax was poor in the lower half of the studied succession (middle Khatatba and Wadi Natrun formations). The very low Tmax values indicate immature OM while VRo and TAI indicated middle stage of oil window to past peak oil generation. The reason for this discrepancy is that the deeper samples are reservoir rocks, not source rocks, and the majority of the organic matter is not composed of reactive kerogen but consists of migrated hydrocarbons and NSO compounds. Contamination due to oil-based mud (OBM) was eliminated because the Abu Tunis-1 × well was drilled in 1969, prior to the extensive use of OBM in drilling. This study showed that a multi-proxy approach is the best way to screen the hydrocarbon potential in a thick succession that contains interbedded source and reservoir rocks.

Thirty-eight cutting samples from the Lower Jurassic to the Upper Cretaceous succession of the Abu Tunis-1X well, north Western Desert of Egypt, were processed palynologically to extract their psilate sporomorphs. This designated practice was made to assess the digitally-quantified progressive changes in the triple Red-Green-Blue (RGB) coloration of sporomorph exine with depth. Stabilization and calibration of the illumination system was applied. Certain precautions were also implemented prior to such digital RGB measurements; for example, some exceptionally lighter (caved) or darker (reworked) specimens were excluded from RGB coloration population samples to avoid misleading results. A minimum of three and up to ten spore grains were studied according to the sample richness and two RGB readings were taken for each selected specimen. The average, standard deviation, and confidence level values for each sample were calculated due to the variable palynological productivity of the samples. In the present study, an attempt was made to monitor and distinguish which of the color components and/or parameters is the most sensitive detector of the progressive maturation changes with depth. By investigating the trends of different parameters of the RGB (i.e. total RGB, R, G, B, R/G) with depth, we were able to distinguish and deduce a linear maturation index from the triple RGB readings. Such a linear maturation index was based on the R component and was successfully correlated and calibrated with other conventional, linear maturity indices (Tmax°C, vitrinite reflectance-VRo%, and thermal alteration index-TAI). The newly modified, RGB-based maturation index called the Kerogen Maturity Index (KMI) can confidently and effectively detect the subtle and progressive changes in kerogen maturation with depth. Such correlation and calibration practices presented herein enabled us to present a modern, reliable, easy to use, and inexpensive measuring technique to assess the thermal maturity of organic matter. The KMI covers the immature and most of the mature phases (early-upper mature) of kerogen and it has its own vitrinite-calibrated cut-offs, which can be correlated with both the Tmax and TAI parameters. This undoubtedly allows the KMI to be easily correlated and complement other classical, expensive maturity indices. This opens the door widely for the palynologists and organic petrologists to use the KMI with good confidence and high reliability for its proven good maturity appraisal.

Research on unconventional shale reservoirs has increased dramatically due to the decline of production from conventional reserves. Geochemical properties and pore microstructures are known to be important factors that affect the storage capacity and nano-mechanical properties of self-sourced organic- rich shales. In this study, eleven shale samples were collected from the Upper and Lower Members of the Bakken Formation for the analysis of mineralogy, geochemical properties, and pore structure. Bulk pyrolysis analysis was conducted using the default method and two modified methods, namely the reservoir and the shale reservoir methods. Although all three methods showed the Bakken samples to be organic-rich and to have considerable remaining hydrocarbon generating potential, it was the shale reservoir method that gave the highest hydrocarbons yield because it captured most of the lighter thermo-vaporizable hydrocarbons. Thus, the shale method is considered to be more appropriate for the geochemical analysis of the Bakken samples. This method also showed that most of the remaining potential is due to the cracking of heavy hydrocarbons, NSO compounds (Resins + Asphaltenes) and kerogen. The organic matter in the samples is mixed II/III type (oil and gas-prone), is thermally mature, and plots at the peak of the oil window. The VRo-eq values, based on solid bitumen Ro measurements and conversion, ranged from 0.85% to 0.98%. The pore structures obtained from the image analysis method showed that total surface porosity of the samples ranged from 3.89% to 11.56% and that organic porosity is not the main contributor of total porosity for the samples analyzed. The pore structures of the samples are heterogeneous due to differences in lacunarity values. Results of the impact of mineralogical composition on pore structures demonstrate that clay minerals and feldspar have a positive influence on porosity while quartz, pyrite, and that TOC has a negative impact.

Geochemical screening is routinely integrated into larger exploration (and sometimes development) programs that also include assessments of the geological setting, petrophysics, mechanical properties of the rock, etc. The Rock-Eval analytical equipment and its classical Basic/Bulk-Rock method have been developed mainly to characterize potential source-rock intervals in petroleum systems. However, with the increasing interest in unconventional plays, it has been recently demonstrated that the use of modified pyrolysis-temperature regimes improves the quantification of hydrocarbons still present in oil-impregnated samples. In spite of their availability, the use of such modified pyrolysis-temperature regimes still remains scarce among users of pyrolysis data (e.g., exploration geologists and geochemists, reservoir engineers, petrophysicists, and other geoscientists). Several cases were selected to portray how different analytical programs are necessary to obtain less biased and more accurate answers to critical questions during prospect and play evaluations and appraisals. Samples originating from conventional and unconventional plays in the Greater Permian Basin of West Texas (Wolfcamp & Spraberry formations), the DJ Basin in Colorado (Niobrara Formation), the Williston Basin (Lower Bakken Shale), and source-rock reservoirs in the Middle East were analysed each using three known different pyrolysis methods, namely the Institut Franҫais du Petrole's “Basic/Bulk-Rock”, “Reservoir”, and “Shale Play”. The Shale Play and Reservoir pyrolysis methods yield oil-in-place estimates 20–42% higher than those yielded by the Basic/Bulk-Rock method on the same sample (e.g., for the Niobrara Formation – 87 bbl oil/ac-ft Bulk method, 118 bbl oil/ac-ft Reservoir method, 119 bbl/ac-ft Shale method; for the Lower Bakken – 194 bbl oil/ac-ft Bulk method, 246 bbl oil/ac-ft Shale method). In addition, a mature, source-rock interval believed to contain gas-prone organic matter (Type III) based solely on TOC and pyrolysis data, was re-interpreted as composed mainly of amorphous oil-prone kerogen, following a multi-component study (which included transmitted and reflected-light organic petrography). These results present unequivocal evidence that underestimating the importance of selecting the proper analytical program can change interpretations dramatically.

The Devonian Antrim Shale is an unconventional biogenic gas accumulation with a technical recoverable resource of 19.9 Tcf. However, major knowledge gaps remain regarding understanding of the source rock potential, organic facies assemblages and paleo-depositional conditions of the Antrim Shale members. This work utilized Rock-Eval pyrolysis, reflected light microscopy and solid bitumen reflectance to characterize the source rock quality, organo-facies assemblages, and thermal maturity of the various Antrim Shale members at three different localities in the Michigan Basin. Results showed that the Lachine and Norwood members are richer in organic matter (up to 24 wt%) than the Upper and Paxton members (

Samples taken from the Upper and Lower members of the Bakken Formation in four wells that were drilled in a northeast - southwest trend along the eastern margin of the Williston Basin in central-western North Dakota were investigated in order to present an overview of source-rock quality and depositional environment conditions for the main purpose of establishing an organofacies model. Several techniques such as Rock-Eval 6 pyrolysis, X-Ray fluorescence elemental analysis, vitrinite reflectance, organic petrography and visual kerogen assessment using reflected and transmitted white light and UV light microscopy on whole-rock pellets were combined to draw the best possible conclusions. The results indicate that kerogen is mainly marine type II with increasing in maturity towards the central and SW portions of the basin. Detailed organic petrography of the samples showed that solid bitumen, amorphous matrix bituminite, granular bitumen, alginite, acritarchs, and liptodetrinite are the most abundant macerals. In order to properly determine the Bakken organofacies, the original hydrogen index (HIo) was restored using various mathematical models and empirical methods. The mathematically restored HIo from thermally mature samples (HIo-Calculated) was then compared to the HI values from thermally immature samples (Tmax

Although organic-rich oil-producing mudrocks have been studied extensively during the last decade, kerogen, as one the main constituents, is not thoroughly understood. The unknowns about kerogen elevate when it comes to its modulus of elasticity. Since kerogen is not as stiff as inorganic minerals, its presence can have a significant impact on the initiation and propagation of fractures in kerogen-rich formations that should undergo stimulation. This study proposes an approach to estimate modulus of elasticity of kerogen with different thermal maturities using Raman spectroscopy. Various shale samples from the upper and lower members of the Bakken Formation were picked from several wells within the Williston Basin in North Dakota, USA. These samples were analyzed using Rock-Eval (RE) pyrolysis and vitrinite reflectance (%Ro) for thermal maturity. In addition, Raman spectroscopic measurements were made on samples and followed by PeakForce AFM for Young's modulus estimation of the organic matter. First, the Raman responses were correlated with the thermal maturity and then, a correlation was established to show the potential relationship between elastic modulus of organic matter and its Raman response based on the maturity levels.

In this study several major source rocks: Kazhdumi, Pabdeh, and Gurpi formations, along with crude oils from the Asmari and Bangestan reservoirs in the Gachsaran oilfield, southwestern Iran, were investigated from the organic geochemistry point of view. Results indicate that the Kazhdumi and Pabdeh formations have excellent generation potential and are mature and immature source rocks, respectively. In contrast, the Gurpi Formation has lower petroleum generation potential. The organic matter in the Kazhdumi and Pabdeh formations in the neighboring synclines within the Gachsaran oilfield is in the late and peak oil generation stages, respectively. SARA composition by Liquid Chromatography performed on four crude oils produced from these source rocks suggest a paraffinic-naphthenic composition. The source rocks had carbonate and shale lithology. Distinct biomarkers point to an open marine environment characterized by marine kerogen Type II and mixed Types II/III deposited under anoxic-suboxic depositional conditions, although. The presence of relatively high amounts of oleanane in the oils points to contribution from a terrigenous source. Based on biomarkers, the four oils exhibit similar thermal maturity, which is equivalent to the primary stage of oil generation. The star diagrams of various normal alkanes and biomarker ratios show that the four crude oil have high similarities, which suggests a single source origin. Nonetheless, utilizing different ML methods of K-means Clustering, Fuzzy C-means clustering (FCM), Comptlayar Neural Network, Construction of agglomerative clusters, and the obtained dendrogram all suggest that there are two oil families in the Gachsaran oil field. Furthermore, geochemical parameters including specific biomarkers denote the contribution of the Kazhdumi and Pabdeh formations in the Gachsaran oil field whereby charges of mixed origins at different reservoir horizons of Asmari and Bangestan can be identified. Ultimately, two scenarios for the presence of oleanane in Bangestan reservoir are envisaged: 1) connectivity of the Asmari and Bangestan reservoirs as a result of natural fracturing, and 2) emplacement of the Pabdeh Formation near the vicinity of the Bangestan reservoir as a result of thrust faulting. Overall, this study demonstrated that integration of data analytics (ML) methods with conventional geochemical techniques can precisely delineate the correlation between the generated oil and the source rocks.

The Late Cretaceous epoch witnessed significant changes in climate and considerable perturbations in the global carbon cycle, among others leading to Oceanic Anoxic Events (OAEs). Investigating the paleoceanographic setting in the southern Tethys (northern Egypt) is critical for a better understanding of the triggering mechanisms that occurred during deposition as a result of a greenhouse climate. Here we present bulk rock geochemical and stable isotopic proxies from the biostratigraphically well constrained Abu Roash A Member (180 m thick) deposited through the late Coniacian–earliest Campanian in the Abu Gharadig Basin of the north Western Desert of Egypt, to investigate whether there was a record of OAE3 and deposition of organic rich facies or oxic Cretaceous Oceanic Red Beds (CORBs). Paleoclimate in this low-latitude Tethyan setting was investigated, where warm to hot greenhouse climate prevailed based on specific dinoflagellate cyst taxa and regional correlation of the δ18Ocarb trends, despite a long-term temperature fall from the mid–Santonian onwards. Low river discharge and terrigenous input during arid conditions, inferred from elemental geochemistry and clay mineralogy, led to low marine productivity during enhanced carbonate production, and thus triggered low organic matter accumulation. The neodymium isotope signatures from bulk carbonate fractions along with available coupled ocean-atmosphere climate models indicate that the studied area witnessed a westward Tethys circumglobal current. These paleocirculation patterns caused enhanced water mixing, resulting in enhanced water column ventilation. These settings led to the deposition of organic-poor CORBs and the absence of the organic-rich OAE3 deposits.

Twenty-four subsurface samples from the Lower Eocene Thebes Formation in the north Gulf of Suez underwent organic geochemical and petrographic analyses. The aim is to evaluate the hydrocarbon source rock potential and understand the organic facies composition of this pre-rift formation, which received little attention. The Thebes Formation is a potential hydrocarbon source rock in the area of the GS 24–1 well with an average TOC of 1.52 wt% (range 0.51–4.23 wt%). The organic geochemical (HI/OI and Pr/Ph vs Pr/n-C17) and petrographic analyses revealed that the organic matter of this conventionally known marine source rock is made up of both marine and terrestrial sources in the Abu Darag sub-basin. The predominant kerogen type II is comprised mainly of liptinitic (dinoflagellate cysts and amorphous organic matter: AOM) and subordinate vitrinitic macerals, which produced mixed cyclo and normal alkanes and some aromatics when subjected to pyrochromatography. The average Tmax value of 428 °C and UV fluorescence of the palynomorphs and AOM indicate that the organic matter has entered the early oil-window stage. The tectonostratigraphic evolution of the Abu Darag sub-basin affected the Thebes Formation source rock quality. More exploration activities across this sub-basin are needed to fully explore the organic facies composition and hydrocarbon potential of the Thebes Formation.

Samples of the Carboniferous oil shale of the Albert Formation in New Brunswick, Canada, were examined using reflected white and fluorescence light microscopy, Rock-Eval pyrolysis, and ICP-MS (for elements). The presence of fractured filled solid bitumen in contact with and within the Albert Formation oil shale indicated that migrated oil had enough force to overcome the tensile strength of oil shale matrix and penetrate the oil shale. Migrating fluid caused thermal alteration of the matrix as evident by the presence primary bitumen and oil droplets. The evidence of oil migration included the presence of solid bitumen and crystalline carbonates in contact with the oil shale. The low permeability oil shale acted as a seal/aquitard and created a diagenetic ‘front’ by slowing the advance of migrating oil, resulting in the formation of a reaction zone. Migrated solid bitumen consisted of both soluble solid bitumen types such as gilsonite and glance-pitch, and insoluble solid bitumen such as wurtzilite and albertite. The variation of Th/K ratio and TOC (wt%) indicates that most of oil shales from the Albert Mine area and within the vicinity of oil migration have higher content of TOC (17–25 wt%) compared to the other Albert oil shales (TOC =

Samples were taken at different levels of thermal maturity in the unconventional Bakken source rock. Programmed pyrolysis derived Tmax, solid bitumen reflectance, liptinite group maceral UV fluorescence, and nuclear magnetic resonance spectroscopy as different thermal maturity indicators were utilized in order to compare redox-sensitive trace metal (TM) concentration to maturity variations and disclose any probable relationship. Comparing redox-sensitive TMs with total organic carbon revealed the presence of anoxic/euxinic conditions in the depositional environment of the Bakken Shale. Although some of the TMs (V and Mo) exhibit slightly positive correlations with some of the thermal maturity indices used in this study, the correlations between other redox-sensitive TMs with maturity were neutral. Collectively, this study demonstrates that thermal maturity may have an impact on some redox-sensitive TMs such as Mo and V concentrations in marine sediments. Additional samples spanning higher maturities will need to be included because there is a possibility that an increase in thermal maturity may lead to the release and liberation of some redox-sensitive TMs from the organic matter (OM) directly. Remineralization and decomposition of OM with thermal maturity advance could release sulfur as a source of thermogenic H2S, which could accelerate pore water/rock interaction and authigenic Fe-sulfides. This could enhance the capability of uptaking of most of the redox-sensitive TMs and increase their concentration in pore water.

The gas adsorption hysteresis effects have strong implications for the characterization of the micropore structure, which is one of the most important properties of shales. This study describes one of the first investigations of low-pressure CO2 adsorption hysteresis illustrated on the Antrim Shale samples, Michigan Basin. A total of 23 samples were characterized by using a combination of X-Ray diffraction (XRD), Rock-Eval pyrolysis, scanning electron microscope (SEM) imaging and CO2 adsorption. The partial least linear regression (PLS) was employed to study the influence of rock composition on the micropore structures and hysteresis index (HI). The results showed that the micropore parameters (surface area and volume) are positively correlated to the amount of organic matter and clay minerals, and have a negative correlation to non-clay minerals. In the Antrim Shale samples, the CO2 adsorption hysteresis seen under low pressure appears to be controlled mainly by the pore network effect caused by the presence of ink-bottle shaped pores, rather than by the swelling of clays and organic matter.

The geochemical and petrophysical complexity of source-rock reservoirs in liquids-rich unconventional (LRU) plays necessitates the implementation of a more expansive analytical protocol for initial play assessment. In this study, original samples from selected source-rock reservoirs in the USA and the UK were analyzed by 22 MHz nuclear magnetic resonance (HF-NMR) T1-T2 mapping, followed by hydrous pyrolysis, and a modified Rock-Eval pyrolysis method (multi-heating step method-MHS). The above methods were complemented by organic petrography under reflected white and UV light excitation of the original and pyrolyzed samples. The analytical protocol presented attempts to better qualify and quantify different petroleum fractions (mobile, heavy hydrocarbons, viscous, solid bitumen), thus provide valuable and refined information about producibility of target intervals during appraisal. Results show how the hydrocarbon fractions interpreted from peak locations and intensities on NMR T1-T2 maps are in good agreement with those from MHS pyrolysis in terms of hydrocarbon mobility/producibility. Results from HP (Hydrous Pyrolysis) experiments show that an exception to this general agreement between NMR and MHS estimates occurs for the Kimmeridge Blackstone Clay samples, where MHS shows an increase of >90% in producible hydrocarbon yields vs. minimal to no presence of mobile hydrocarbons in NMR T1-T2 maps. This study clarifies the role of pore structure and networks in these discrepancies of producible oil estimates when comparing programmed pyrolysis to NMR-based techniques. This novel, multi-step and multidisciplinary approach provides a more advanced screening protocol for identifying zones of higher oil-in-place (OIP) and predicting fluid mobility prior to drilling or completions.

An integrated approach based on organic petrographic and geochemical proxies along with palynological and palynofacies analysis were employed using 24 rock samples representing the upper part of the Quse and Sewa formations in the southern Qiangtang Basin, Tibetan Plateau, SW China. This interval was deposited during the Early Jurassic Toarcian Oceanic Anoxic Event (T-OAE) and is investigated to assess the biostratigraphic age control based on palynomorphs composition. The current approach allows for the interpretation of the local paleoenvironmental response to T-OAE climate variability that still unraveled based on palynofacies analysis of the Bilong co succession. Visual palynofacies analysis, vitrinite reflectance (VRo), and total organic carbon (TOC)/Rock-Eval pyrolysis parameters enables a detailed assessment of probable source rock characterization. The palynomorph content comprises mainly terrestrially-derived land-plants, mostly sphaeromorphs pollen grains, with minor content of marine dinoflagellate cysts (dinocysts). Marker dinocysts and pollen taxa allow the subdivision of the studied succession into two age-distinctive units of early Toarcian and late Bajocian-Bathonian. Additionally, carbon isotope profile of the studied succession observed a large negative carbon isotope excursion (CIE) within the lower Toarcian oil shale interval, which is compatible with regional δ13Corg records from adjacent basins at this time. The regional TOC contents of lower Toarcian reached up to 21 wt% in areas of the eastern Tethys compared to lower values in the western Tethys and Boreal (ca. 3 wt%). Two palynofacies assemblages revealed deposition of these deposits in distal inner neritic to fluvio-deltaic environment and to some extent in brackish marginal marine setting. Geochemical screening indicated that most samples were dominated by very good to excellent organic matter richness of kerogen Type II and mixed Type II/III with very good to excellent hydrocarbon generation. The calculated VRo-eq from Rock-Eval Tmax and measured VRo values are in good agreement and showed that the organic matter of the studied interval is in the early to middle stages of the oil window.

Samples from the Devonian succession in the Sifa-1X well located mid-way between the Egyptian Faghur Basin and the Libyan Cyrenaica Platform were examined in this study. The distribution of liptinite group macerals was investigated under reflected and transmitted light microscopy. Diverse and abundant liptinites of terrigenous and marine origin were identified. The palynological investigations included analysis of the miospores assemblages and palynofacies categories by multiple statistical approaches in addition to calculation of the sedimentation rates. These analyses signified four miospores biotopes and three palynofacies biotopes that were used to assess the ramps of paleoclimatological and paleoenvironmental changes during sedimentation. These biotopes were used to define a model of liptinite maceral distribution throughout the Devonian in the study area. The model suggested two different phases of basinal dynamics in terms of climate, sea level, and sedimentation rates, namely an Early-Middle Devonian transgressive phase and a Late Devonian regressive phase. Conditions during the Early-Middle Devonian transgressive phase were oxic to dysoxic with low sedimentation rates and oxic during the Late Devonian regressive phase. Oxygen depletion was under the threshold required to induce significant preservation of the quantity and quality of organic matter, including liptinite macerals. The redox conditions were confirmed by trace element analysis. The high oxygen level affected both the quantity and quality of the liptinite macerals and greatly reduced the preservation of the amorphous organic matter. The quality of the organic matter varied from kerogen type I, II, mixed types II/III and type III. The mixture of these kerogen types was assessed by organic elemental and pyrolysis gas chromatography analyses. In addition, the entire Devonian succession in the Sifa-1X well is in the oil window, as also indicated by miospore coloration. This indicates that the organic matter in the Devonian strata have the potential to generate oil and gas.

The study area, located in the northern rim of the Greater Green River Basin, Wyoming, is a large anticlinal feature with a complex structural history and extensive fracturing. The targets are the Late Cretaceous Steele Shale and the Niobrara Formation, having a combined thickness of 3700–4900 ft. The productive intervals have a depth ranging from 8500 to 13,000 ft. Total Organic Carbon content in one of the wells drilled, the Bare Ring Butte 4–36, ranges from 0.5 wt.% to 4.0 wt.% and averages 2.0 wt.%. Hydrogen Index ranges from 50 to 220 mg HC/g TOC. Gas content averages 30 scf/t (as-received) and porosity for the inferred pay zone is estimated at 3–6%. Matrix permeability is low, estimated to be 130 nD (nano-Darcy). Mineralogy in the above well consists of 40 wt.% quartz, with illite, fracture-filling calcite and chlorite also present. The shales are overpressured, have a gradient of 0.7 psi/ft., and they lie within the oil and condensate liquids windows. At Bare Ring Butte 4–36, vitrinite reflectance (%R o , maximum) ranges from 0.85% at 8000 ft. to 1.20% at 10,200 ft. A distinct change in the maturation and vitrinite reflectance gradients with depth is evident in this well, which coincides with the top of the overpressure zone. The overpressure zone has a thin wet (oil) zone (34–46° API) at the top, followed by a thick gas-saturated zone underneath. A similar trend was also seen in at least four more wells in the Antelope Arch area. Using an imaging tool, three highly-fractured zones with a combined thickness of 600 ft. have been identified in the Steele/Niobrara interval in the Bare Ring Butte 4–36 well. The recoverable gas resource is estimated to be 5 Bcf/160 acres (1/4 section) using a recovery factor of only 5%. In the early 1980s, vertical wells tested 1.4 to 3.7 Mmcf/d following natural completion in the Steele Shale and Niobrara Formation. The closest analogue to the Steele Shale and Niobrara Formation is the stratigraphically-equivalent Baxter Shale in Wyoming. Questar E&P has drilled a number of vertical and horizontal wells in the Baxter Shale. Vertical wells that targeted fractured zones had IP (initial production) rates ranging from 1.8 to 9 Mmcf/d. Questar estimated a EUR (estimated ultimate recovery) of 8–16 Bcf for vertical wells drilled on 160-acres with recovery factors of 7–15%. A horizontal well (3000 ft. long) that encountered a natural fracture swarm had an IP rate of 9.1 Mmcf/d in the first 4–5 days before it stabilized at 2.7 Mmcf/d. With today's improved drilling and stimulation techniques, horizontal wells targeting the highly-fractured zones could improve productivity considerably. Because of the great thickness, highly-fractured character, and overpressured nature, the Steele Shale and Niobrara Formation could have greater resource potential than the normally-pressured Barnett Shale in the core area of the Fort Worth Basin.

Mineralogy and elemental concentration of two coal seams in Alberta, Canada, were determined using X-ray diffractometry and X-ray fluorescence (XRF). Minerals consist mainly of quartz and calcium minerals, the latter as calcite and vaterite, and oxalate (whewellite). Clay minerals are present as kaolinite, reflecting peat deposition in an acidic environment. Most elements in the coal show depletion compared to Clarke values. Some elements are associated with mineral matter (e.g., Ti, Ba, Si, Al, K, Mg, and Y) and increase with ash. Na, Mn, Sr, and Cu are associated with macerals. High phosphorous and strontium in one interval may be related to the high concentration of whewellite.

The Gulf of Suez area in eastern Egypt is one of the most prospective and promising hydrocarbon provinces all over the world. Sixty drill cuttings samples of the Upper Cretaceous Raha Formation (70–120 m) have earlier been processed for their palynomorph and palynofacies contents, including 36 geochemically screened samples for their source-rock potential using TOC, Rock-Eval®. 6 Turbo, the new Rock-Eval® 7S instrument along with one of its latest modules, the CleanSim method. The combination between visual palynofacies and RGB-based sporomorph color image analysis along with the geochemical results are presented as part of a detailed assessment of the organic matter (OM) types, OM-richness, and thermal maturity levels. Palynofacies analysis defined three associations of OM types. The first and third associations consist of kerogen Type II; the former is dominated by a moderate abundance of amorphous organic matter (AOM) and phytoclasts, whilst the latter is dominated by high AOM content. Conversely, the second association is dominated by terrigenous fragments of gas-prone Type-III kerogen. The application of RGB analysis indicated a thermally immature to mature stage for some intervals in one of the three studied wells, the B-109. Geochemical screening results led to divide the Raha Formation into three distinctive groups, which are characterized by varied OM qualities and quantities, hydrocarbon potential, and thermal maturity levels. Varied thermal maturity levels was related directly to the Late Cretaceous tectonics like the effect of Syrian Arc System and the Oligocene-Miocene syn-rift activity that led to the opening of the Gulf of Suez. Differences in kerogen types were observed between geochemical and palynofacies analyses. Microscopic investigations of palynofacies-dominated AOM suggested that most AOM particles were of terrigenous origin due to the effect of biodegradation and gradual transformation of phytoclasts into AOM, reflecting a kerogen Type III instead of kerogen Type II that was indicated by palynofacies analysis ternary plots.

Rock-Eval pyrolysis/TOC, petrographic, and geochemical data available in the public domain for a total of 296 core and 243 drill cuttings samples from the Albian-early Cenomanian Kharita and Bahariya formations of four main basins, Shushan, Abu Gharadig, Matruh and Dahab-Mireir, were reviewed. This review provides a comprehensive overview to understand the organic richness, type, and thermal maturity of potential source rock intervals within the Kharita and Bahariya formations in northern Egypt by means of burial history modeling and oil-in-place calculations. Geochemical data of both formations confirmed the presence of up to excellent source rocks of varied kerogen types but mainly of Type III (gas-prone) and mixed types II/III. Thermal maturity levels ranged from immature to the early stage of oil window, although some intervals reached the peak oil window in the Abu Gharadig and Shushan basins compared to their counterparts. The depositional paleoenvironment of the Kharita and Bahariya formations is interpreted based on the organic biomarker compounds and palynofacies associations. Generally, both formations in the four basins were interpreted to accumulate in a fluvio-deltaic to marginal marine setting, although the Kharita rock unit was slightly less marine based on the isoprenoids pristane and phytane to nC17 and nC18 ratios. The ratio of 22S/(22S + 22R) for the homohopanes C31 and C32 of Kharita oils from the Shushan Basin ranged from 0.50 to 0.60, indicating marginally mature to the onset of oil generation. However, common amongst much of the previous studies was the notable differences in organic matter contents, thermal maturity levels and hydrocarbon potential. Environmental and ecological processes, including proximity to shoreline, terrestrial/riverine input, oxygenation levels and water column conditions, are considered the primary drivers that triggered variable amounts of organic carbon accumulation. While differences in thermal maturity levels were attributed to tectonic activities and related structural processes.

The Lower Bakken Shale is a key member of the Bakken Petroleum System, which is a prolific unconventional accumulation in North America. Unconventional accumulations have unpredictable lateral variations in hydrocarbon production due to a variety of factors including porosity, permeability, and other rock properties. Therefore, understanding the geochemical (source rock potential), petrological, and petrophysical properties of these units is essential in evaluating the hydrocarbon potential for the Lower Bakken Shale. This study utilized cores from four wells within three fields in Divide County, North Dakota, with samples collected for Rock- Eval pyrolysis, organic petrology, petrographic thin section studies, XRD, SEM, porosity, pore size, and pore fluid distribution. Helium porosimetry and NMR T2 porosity techniques were used to estimate porosity and also to check the quality of the results and avoid discrepancies. Results showed that maturity in the study area varies from immature to early mature using Tmax and solid bitumen reflectance. Organic petrology showed the dominance of solid bitumen and marine alginites, which confirms the Type II kerogen identified from pyrolysis and marine depositional environment in the study area. Major organic matter types identified from SEM studies involve stringy OM, OM-mineral admixture, particulate OM and pure OM which host the majority of the organic matter pores. Furthermore, pore types identified from SEM include mineral matrix pores, organic matter pores, and microfracture pores. Porosity values based on both helium and NMR varies but the difference was nominal and attributed to the presence of abundant clay minerals. Pore sizes are distributed within micropores, mesopores, and macropores with thermal maturity, TOC, and clay mineral proportion having a major influence on pore distribution. Clay-bound water was identified to be the dominant fluid within the shale samples using the T2 cutoff values and supporting evidence from the abundance of clay matrix porosity.

An interlaboratory study (ILS) was conducted to test reproducibility of vitrinite and solid bitumen reflectance measurements in six mudrock samples from United States unconventional source-rock reservoir petroleum systems. Samples selected from the Marcellus, Haynesville, Eagle Ford, Barnett, Bakken and Woodford are representative of resource plays currently under exploitation in North America. All samples are from marine depositional environments, are thermally mature (T >445 °C) and have moderate to high organic matter content (2.9–11.6 wt% TOC). Their organic matter is dominated by solid bitumen, which contains intraparticle nano-porosity. Visual evaluation of organic nano-porosity (pore sizes < 100 nm) via SEM suggests that intraparticle organic nano-pores are most abundant in dry gas maturity samples and less abundant at lower wet gas/condensate and peak oil maturities. Samples were distributed to ILS participants in forty laboratories in the Americas, Europe, Africa and Australia; thirty-seven independent sets of results were received. Mean vitrinite reflectance (VR) values from all ILS participants range from 0.90 to 1.83% whereas mean solid bitumen reflectance (BR) values range from 0.85 to 2.04% (no outlying values excluded), confirming the thermally mature nature of all six samples. Using multiple statistical approaches to eliminate outlying values, we evaluated reproducibility limit R, the maximum difference between valid mean reflectance results obtained on the same sample by different operators in different laboratories using different instruments. Removal of outlying values where the individual signed multiple of standard deviation was >1.0 produced lowest R values, generally ≤0.5% (absolute reflectance), similar to a prior ILS for similar samples. Other traditional approaches to outlier removal (outside mean ± 1.5*interquartile range and outside F10 to F90 percentile range) also produced similar R values. Standard deviation values < 0.15*(VR or BR) reduce R and should be a requirement of dispersed organic matter reflectance analysis. After outlier removal, R values were 0.1%–0.2% for peak oil thermal maturity, about 0.3% for wet gas/condensate maturity and 0.4%–0.5% for dry gas maturity. That is, these R values represent the uncertainty (in absolute reflectance) that users of vitrinite and solid bitumen reflectance data should assign to any one individual reported mean reflectance value from a similar thermal maturity mudrock sample. R values of this magnitude indicate a need for further standardization of reflectance measurement of dispersed organic matter. Furthermore, these R values quantify realistic interlaboratory measurement dispersion for a difficult but critically important analytical technique necessary for thermal maturity determination in the source-rock reservoirs of unconventional petroleum systems., This research was funded by the USGS Energy Resources Program.

Bacteria are ubiquitous in all depositional environments, especially in marine environments where anoxic/euxinic conditions prevail. In such environments, sulfate-reducing bacteria play a critical role to supply sulfur as a biogenic source for H2S through biomass degradation. In the biodegradation process, chemical and mechanical properties of the organic matter alter. In order to document these variations in-situ, selected samples from a deeply buried mudrock (Bakken Formation), were examined through microscopy analysis. Two separate but adjacent telalginite particles were selected; An unaltered telalginite and a bacterially degraded telalginite, which still contains relicts of the parent Tasmanites. A combination of AFM-based IR spectroscopy with high-resolution amplitude-frequency modulation was used to evaluate and compare the physicochemical variations across these two particles at the nanoscale. Results indicate that all aromaticity indexes increase for both particles but at a higher rate as a result of bacterial degradation. Furthermore, it was found that bacterial degradation imposes a major mechanical heterogeneity to the organic matter under study, which was detected through phase imaging and modulus mapping captured from submicron to micron-scale level, which exposed the remnants of the parent Tasmanites. This study reveals that bacterial degradation can accelerate the maturation process, thus the generation of hydrocarbons from the kerogen to happen at the earlier stages of thermal adavance.

Vitrinite reflectance generally is considered the most robust thermal maturity parameter available for application to hydrocarbon exploration and petroleum system evaluation. However, until 2011 there was no standardized methodology available to provide guidelines for vitrinite reflectance measurements in shale. Efforts to correct this deficiency resulted in publication of ASTM D7708: Standard test method for microscopical determination of the reflectance of vitrinite dispersed in sedimentary rocks .I n 2012e2013, an interlaboratory exercise was conducted to establish precision limits for the D7708 measurement

This study aims to differentiate between bacteria-algae interactions and thermal maturation, at the same time, shed light on the hydrocarbon generation pathways based on chemical changes at the submicron scale. For this goal, samples were taken from the lower shale member of the Bakken Formation in Willison Basin at the early and peak thermal maturity stages and analyzed with surface probes. Sample selection was based on bulk geochemical screening, organic petrology and fluorescence emission of the liptinite group macerals and solid bitumen reflectance. Submicron scale chemical heterogeneity resulting from biodegradation and different thermal maturity pathways was documented and compared using AFM-based Nano-IR spectroscopy. A significant chemical heterogeneity was noticed within unaltered telalginite and bacterially degraded Tasmanites, and also between solid bitumen particles that were adjacent to the telalginite at the same stage of maturity. Results suggest that separate pathways of maturation took place in the neighboring solid bitumen particles based on their infrared spectroscopic data. It was also found that thermal maturity progression reduced chemical heterogeneity in the organic matter particles. During bacterial degradation, Tasmanites lost its fluorescence emission while its relative chemical heterogeneity increased compared to the unaltered telalginite, a feature that has been reported at such a very fine scale of measurement. This study will ultimately improve our understanding of the processes that may result in hydrocarbon generation from organic matter.

A recent study of selected samples from the Cretaceous (Albian) Kharita Formation of Egypt revealed very good to excellent source rock (SR) potential for six intraformational, organic-rich intervals. This work investigates the SR potential of the entire Kharita Formation across the Matruh Basin, using samples from two wells: the Abu Tunis 1X well from the central part of the basin, and the Siqeifa 1X well drilled on the eastern margin of the basin. More strongly reducing conditions were developed in the centre of the basin, and resulted in the deposition of more organic-rich shales by comparison to the less reducing conditions that prevailed on the eastern basin margin, where the shales contain less organic matter. Deltaic intraformational shales and carbonates in the Kharita Formation of Abu Tunis 1X constitute a significant 120 m net of the potential SR. The lower Kharita Formation contains 34 m net shale SR of good to very good/excellent organic richness, yielding values of 1.14–11.59 wt % total organic carbon (TOC). The organic matter has low Hydrogen Index (HI) values (184–389 mg HC/g TOC) and amorphous organic matter (AOM) and relatively high non-opaque phytoclast frequencies indicating mainly gas/oil-prone organofacies (kerogen Types III/II). The upper Kharita is rather important, containing 86 m net shale/carbonate SR that has fair to good organic richness (0.8–1.8 wt % TOC), and lower HI (126–250 mg HC/g TOC), a dominance of non-opaque phytoclasts, and subordinate AOM frequencies, which together indicate gas/oil-prone organofacies (kerogen III/II). In the Siqeifa 1X well, Kharita deltaic intraformational shales and shaley dolostones comprise 80 m net SR, which has mainly fair to good to less very good organic richness (0.8–2.1 wt % TOC), whilst low HI (93–220 mg HC/g TOC), dominance of non-opaque phytoclasts and subordinate AOM indicate gas-prone organofacies (kerogen Type III). A relative upward increase in deposition of lignite and coaly carbonaceous material supports a gas-prone organofacies. Whilst thermal maturity indices only point to immature to early mature (pre- to early oil-window) SRs in both the Abu Tunis 1X and Siqeifa 1X wells, hydrocarbon exploration focussing on this potential source rock may be justified in areas to the southeast of the Matruh Basin, where modelling indicates this unit may have reached the late mature oil- to main gas-generation windows.

This study reviews specific public geochemical data (mainly TOC and Rock-Eval Pyrolysis parameters) of the Mancos Shale and the Lewis Shale located in an area to the south of the San Juan Basin, New Mexico. Both shale formations are immature within the study area proper and surrounding acreage. Maturity increases in a southeastern direction within the study area and is the only location where the Mancos Shale has thermogenic gas generating potential. The quality of the organic matter (kerogen) reported for the Mancos and the Lewis shales is mostly of Type III (gas-prone) with Type II being less dominant. The thicknesses of both the Mancos and Lewis shales are adequate to generate and store large volumes of natural gas in the thermally mature areas. The study area is also faulted, which may provide opportunities for natural fracturing to have formed. Furthermore, silt and sand layers within the Mancos Shale could provide permeability pathways for the gas, in a similar fashion to the Lewis Shale in the San Juan Basin. The part of the study area that belongs to the Albuquerque Basin contains thick sections of the Mancos Shale but at great depths (> 13,000 ft or > 4 km). However, it might be possible to find prospective areas near the margins of the basin, particularly if there is an active hydrologic system that operates close to the shale that may be responsible for late-stage biogenic gas generation.

The Paleocene-age Wasatch and Fort Union Formations in the study area contain numerous coal seams that are interbedded with shale, sandstone, and conglomerates. Individual seam thickness ranges from 2 to 15 ft (0.6–4.6 m) and aggregate thickness ranges from 64 to 163 ft (19.5–49.7 m). The coals are of sub-bituminous to high-volatile C/B bituminous rank (Ro,ran = 0.47 to 0.59%) and are found at depths from 3 /g (ARB), which is higher than expected for the coal rank. The coals appear to be close to full saturation, based on a comparison of adsorption isotherms with desorption data. The coals pinch-out updip in the subsurface forming a stratigraphic trap, which may explain the high gas content and the mixed biogenic–thermogenic origin supported by isotopic analysis. Gas composition is 97% methane with 3% inerts, and the gas has a heating value of 990 BTU/ft 3 . The coals are relatively clean (average ash content is 15 wt.%) and have fast diffusivity (63% of total gas desorbs in 3 ) with wells drilled on 80-acre spacing, which translates to a gross EUR of 1.4 BCF per well for the 500 well locations identified in the developable acreage. Based on numerical simulation using the simplistic Fekete TM model, peak coal gas rate is expected to be 320 MCF/D (9014 m 3 per day) after 36 months, and production should remain at that level for 12 months before declining at a rate of 10% per year. Conventional gas potential also exists in numerous intervals within the Upper Fort Union and Wasatch Formations sandstones at depths shallower than 2000 ft (526 m). Few wells drilled decades ago, having perforations in these sands, showed IP (initial production) rates ranging from 500 MCF/D (14,084 m 3 per day) to 12 MMCF/D (338,028 m 3 per day). A 24-inch (60 cm) diameter pipeline that has an operating pressure of 800–1000 psig, a tap, and a capacity of 275 MMCF/D (7.74 million m 3 per day) crosses the study area. The pipeline is connected to the Colorado Interstate Gas mainline, which provides gas to markets in the eastern United States.

Oil hosted in a rock taken from a seep exposed by a road cut in north-central Peru was studied by geochemical means. The oil is classified as heavy paraffinic (waxy) by liquid chromatography. The oil appears to be highly mature, showing evidence of chemical and/or biological degradation. This is further supported by relatively high yields of polar fractions (resins and asphaltenes), partial depletion of n-alkanes below C16, and a relative enrichment of isoprenoid hydrocarbons. The n-alkane distribution obtained by whole-oil gas chromatography (GC) also points to mature, waxy oil. Pristane/phytane and isoprenoid ratios suggest that Type II kerogen deposited in low-oxygen (dystrophic) environment was likely the source of the oil. Biomarker fingerprints of the saturate fraction obtained by gas chromatography–mass spectrometry (GC–MS) and other characteristic ratios indicate the high level of thermal maturation of the oil and suggest that the oil was derived from a clay-rich source rock rich in bacterial-derived organic matter deposited in suboxic conditions. Aromatic biomarker data confirm the high level of thermal maturity of the oil and point to a mixed shale/carbonate source rock deposited in a sulfate-poor marine environment. The parent oil most likely has a pre-Cretaceous source due to the absence of 18 α (H) oleanane and the fact that the C28 αββ/C29 αββ steranes and the C28 αββ/C29 αββ sterane vs. C27 αββ/C29 αββ sterane ratios are both comparable to values reported for oils derived from the Jurassic Pucara Formation source rock in the nearby Maranon Basin.

Vitrinite maturity and programmed pyrolysis are conventional methods to evaluate organic matter (OM) regarding its thermal maturity. Moreover, vitrinite reflectance analysis can be difficult if prepared samples have no primary vitrinite or dispersed widely. Raman spectroscopy is a nondestructive method that has been used in the last decade for maturity evaluation of organic matter by detecting structural transformations, however, it might suffer from fluorescence background in low mature samples. In this study, four samples of different maturities from both shale formations of Bakken (the upper and lower members) Formation were collected and analyzed with Rock-Eval (RE) and Raman spectroscopy. In the next step, portions of the same samples were then used for the isolation of kerogen and analyzed by Raman spectroscopy. Results showed that Raman spectroscopy, by detecting structural information of OM, could reflect thermal maturity parameters that were derived from programmed pyrolysis. Moreover, isolating kerogen will reduce the background noise (fluorescence) in the samples dramatically and yield a better spectrum. The study showed that thermal properties of OM could be precisely reflected in Raman signals.