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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.

Seventeen coal and carbonaceous shale samples taken from eight stratigraphic sections of the Devonian Hecla Bay and Weatherall formations in Arctic Canada, were examined using reflected light microscopy, instrumental neutron activation analysis (INAA), and inductively coupled plasma emission spectroscopy (ICPES). Samples consist of humic coal with 62–79 vol% vitrinite, liptinite-rich humic coal with 42 vol% liptinite, and cannel coal with 52–81 vol% sporinite content. Carbonaceous shale has 46–73 vol% mineral matter and canneloid shale has 30–42 vol% mineral matter as well as 22–38 vol% sporinite content. Most were deposited in areas characterized by minor channel cut-and-abandonment and lake and bay infills peripheral to distributary complexes. A fresh water environment is indicated by Boron (18–71 ppm), low inertinite (0–7.8 wt%), and high sporinite content (30–81 vol%). The ratio of Na/K versus liptinite content shows that coals and associated sediments from the Hecla Bay Formation experienced a more rapid rate of sedimentation than the carbonaceous shales from the Weatherall Formation. The highest total REEs and LREE (La-Gd) was in the liptinite-rich humic coal, followed by humic coal and carbonaceous shale. The concentration of REEs and LREEs in the cannel coals is half of that measured in the liptinite-rich humic coal. The PAAS normalized for oil shales follows two different patterns: 1) the liptinite-rich coal samples display a sharp increase from Nd to Ho, then maintain a similar pattern up to Lu; and 2) samples of other lithologies increase from Nd to Dy, and then maintain a flat trend up to Lu. Hierarchical cluster analysis shows that canneloid and liptinite-rich coal exhibit the greatest similarity with each other whereas humic coal and liptinite-rich coal show the greatest dissimilarity with carbonaceous shale.

Understanding pore heterogeneity can enable us to obtain a deeper insight into the flow and transport processes in any porous medium. In this study, multifractal analysis was employed to analyze gas adsorption isotherms (CO2 and N2) for pore structure characterization in both a source (Upper-Lower Bakken) and a reservoir rock (Middle Bakken). For this purpose, detected micropores from CO2 adsorption isotherms and meso-macropores from N2 adsorption isotherms were analyzed separately. The results showed that the generalized dimensions derived from CO2 and the N2 adsorption isotherms decrease as q increases, demonstrating a multifractal behavior followed by f(α) curves of all pores exhibiting a very strong asymmetry shape. Samples from the Middle Bakken demonstrated the smallest average H value and largest average α10−-α10+ for micropores while samples from the Upper Bakken depicted the highest average α10−-α10+ for the meso-macropores. This indicated that the Middle Bakken and the Upper Bakken have the largest micropore and meso-macropore heterogeneity, respectively. The impact of rock composition on pore structures showed that organic matter could increase the micropore connectivity and reduce micropore heterogeneity. Also, organic matter will reduce meso-macropore connectivity and increase meso-macropore heterogeneity. We were not able to establish a robust relationship between maturity and pore heterogeneity of the source rock samples from the Bakken.

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.

Understanding the pore structures of unconventional reservoirs such as shale can assist in estimating their elastic transport and storage properties, thus enhancing the hydrocarbon recovery from such massive resources. Bakken Shale Formation is one of the largest shale oil reserves worldwide located in the Williston Basin, North America. In this paper, we collected a few samples from the Bakken and characterized their properties by using complementary methods including X-ray diffraction (XRD), N2 and CO2 adsorption, and Rock-Eval pyrolysis. The results showed that all range of pore sizes: micro ( 50 nm) exist in the Bakken shale samples. Meso-pores and macro-pores are the main contributors to the porosity for these samples. Compared with the Middle Bakken, samples from Upper and Lower Bakken own more micro pore volumes. Fractal dimension analysis was performed on the pore size distribution data, and the results indicated more complex pore structures for samples taken from the Upper and Lower Bakken shales than the Middle Bakken. Furthermore, the deconvolution of the pore distribution function from the combination of N2 and CO2 adsorption results proved that five typical pore size families exist in the Bakken shale samples: one micro-pore, one macro-pore and three meso-pore size families. The studies on the correlations between the compositions and the pore structures showed that mostly feldspar and pyrite affect the total pore volume of samples from Middle Bakken Formation whereas clay dominates the total pore volume of samples from Upper/Lower Bakken Formation. TOC and clay content are the major contributors to the micro-pore size family in the Upper/Lower Bakken. Also, it was observed that the increase of hard minerals could increase the percentage of macro-pore family in the Middle Bakken 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.

The thermal maturity from the Early Paleozoic strata in Northwestern Argentina was studied using reflected light microscopy and Rock-Eval analyses. The graptolites were collected from the Acoite and Lipeon formations, at the Los Colorados section, Cordillera Oriental, and the Huaytiquina, and Munayoc sections, Puna highland, corresponding to the "Coquena" Formation and the Cochinoca-Escaya Magmatic-Sedimentary Complex. Rock-Eval parameters were unreliable due to the low TOC, S1, and S2 values. The Cordillera Oriental region sediments have low maturity based on low reflectance (%GRo= 0.63%–1.11%) and anisotropy of graptolites. In contrast, the higher graptolite reflectance of samples from the Munayoc and Huaytiquina sections (%GRo= 5.57%–6.62%), in the Puna region, indicates considerably higher maturity. This could result from the combination of hydrothermal fluids with a temperature range from 336 °C to 358 °C, associated volcanism, and deformation related to tectonics events, which produced a higher geothermal gradient in the Puna. The Los Colorados section's thermal maturity modeling shows a better fit considering erosion episodes at the Late Paleozoic and Early Cenozoic. However, more studies about geothermal parameters and stratigraphy are necessary to corroborate these preliminary models and propose new approaches for the Puna region.

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 petrography of two coal seams in Alberta was determined using reflected light microscopy. Random reflectance is 0.36%, indicating a lignite rank. Huminite is dominant over liptinite and inertinite. Maceral assemblage suggests a wet forest moor depositional paleoenvironment. The predominance of telohuminite and gelohuminite over detrohuminite and inertodetrinite reveals peat formation in a rather reducing environment and a rapid burial of the peat, which prevented any significant oxidation. A few intervals with high levels of oxyfusinite reveal periodic drops of the water table. Results coincide with the interpretation based on the Na/K ratio, which is used as an indicator of the rate of sedimentation.

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.

Geochemical and palynological proxies were determined for 31 samples representing the upper Coniacian-lowermost Campanian Abu Roash A Member, collected from the BED2-3 well. This was done to assess the prevailing paleoredox conditions, productivity levels, and water-column settings to: (1) understand controls and mechanisms related to accumulation of organic carbon within the sedimentary record; (2) assess principal environmental processes that triggered the preservation of organic matter-poor, calcareous shale and limestone facies of the Abo Roash A Member; and (3) to interpret the paleoceanographic settings and confirm the occurrence of either Oceanic Anoxic Event 3 (OAE3) or Cretaceous Oceanic Red Beds (CORBs) within the Abu Gharadig Basin in the southern part of the Tethyan Ocean, Egypt. Sedimentation rates were reconstructed based on the biostratigraphic-age constraints of marine dinoflagellate cysts (dinocysts). Trace elements-based ratios and relationships were used in order to study the role of clastic terrestrial input. Three groups of dinocysts and freshwater Pediastrum algae were used to study the water-column conditions. Results showed that the Abu Roash A Member was deposited under oxic to intermittently dysoxic conditions in a distal inner to middle neritic environment, with varying sedimentation rates from 32 to 119 mm kyr−1. Productivity appeared to be a significant factor for determining magnitudes of the organic carbon accumulation; however, low productivity was prevalent during deposition. Carbonate content was high, which resulted in dilution of organic matter during varied rates of sediment input. Such results indicate that the paleoceanographic conditions in the southern Tethys witnessed the absence of prevalent oceanic anoxia (i.e., the Coniacian-Santonian OAE 3) and deposition of the CORBs as in several parts of the Tethys, the Pacific, and the Indian oceans.

The methods used in allocating commingled production in conventional reservoirs are similar to those that are effective in performing the same task on unconventional reservoirs. However, the protocols to follow can vary a great deal. The presence of distinct endmembers in the former allows the use of the method of production allocation using peak height ratios and mixing curves and using linear regression of peak heights. Due to the possible contribution from multiple intervals in the same formation or even from different formations as in the case of fracture stimulated unconventional reservoirs, the combined application of methods that compare the quantities and carbon stable isotopes of selected compounds (such as saturate and aromatic hydrocarbons) and other parameters (such as API gravity) was employed. This was done based on a series of samples presumed to represent the endmembers via their HRGC and GCMS oil fingerprint, followed by the determination of the contribution from each sample by using an algebraic solution of simultaneous linear equations. A review of the two methods is provided. The aforementioned method for unconventional resources is demonstrated in a case study of production allocation that was performed on three produced oils sampled at different times from three separate wells, “A” “C”, and “D”, located in the Western Canadian Sedimentary Basin. A total of 25 core extract samples representing two producing zones (end members) of the Montney Formation (i.e., the Middle and the Lower Montney) from well “A” and “B” were used. Results of GC and GCMS analyses of the samples were evaluated; rigorous filters, cluster analysis (dendrograms), and Principal Component Analysis (PCA) were applied to identify any clustering or variation between the samples representing possible contributor layers and the commingled oil. Then, using proprietary software and statistical techniques, the fingerprint of selected compounds was qualitatively compared and their quantity in each of the rock extracts and the produced oils was determined in order to allocate the contribution from the two end members that each extract belongs to. Results from the method for unconventional resources were compared to other data (such as GC trace patterns) for consistency. The case study demonstrates that a combined approach that accounts for the entire fingerprint (i.e., GC and molecular markers (including biomarker and non-biomarker parameters)), produces the best results and minimizes uncertainty.

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.

This study describes the main technical challenges encountered while drilling the first horizontal coalbed methane well ever attempted in Canada. The well was drilled in the deep (>1,300 m), low-permeability (1–3 md) coals of the Lower Cretaceous Mannville Formation in the central Alberta Plains. The study also discusses the investigation that followed the occurrence of a few unexpected events during the drilling phase of the well, as well as the stability analysis of the horizontal borehole conducted. Suggestions are made on how to best mitigate the risk of getting the drill pipe stuck and potentially losing the hole along with drilling equipment. The findings are very instructive and should have an application in geological settings similar to those found in the Alberta Basin. Any modifications on how to drill horizontal wells in coal seams present at great depths and under high in-situ stresses must take into account the geomechanical properties of the target seam through triaxial testing, whi...

Borehole stability analysis was conducted using STABView and FLAC geomechanical modeling for a horizontal coalbed methane well in the San Juan Basin. The objective was to determine whether the coal seam at 3,000 ft depth would yield under certain drilling and production conditions. Triaxial tests using 1-inch diameter core plugs were performed to construct the Mohr-Coulomb and Hoek-Brown failure envelopes. A reduction of the peak coal strength by approximately 30% was needed to correct the scale-dependent strength to a value that was thought to be more representative for a 4.75-inch diameter horizontal borehole. No yielding was predicted at underbalanced and overbalanced drilling conditions when the uncorrected M-C and H-B lab strength data were used. A 30% reduction in peak strength predicted no yielding during overbalanced drilling and only minor yielding during underbalanced drilling or production. The maximum extent of the yielded zone at BHP of 100 psi predicted by STABView was 37% over gaug...