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Widespread deposition of siliciclastic sediments with consequent alternations between fine-grained siltstones and shales versus coarse-grained sandstones in the north Western Desert of Egypt provides an archive for mid-Cretaceous sea-level oscillations. This study presents elemental geochemical data as well as palynofacies and palynomorph components of upper Albian reservoirs in the Abu Gharadig Basin, north Western Desert. During the mid-Cretaceous, the studied area is located in the transition zone between the fluvio-deltaic and shallow marine settings at the southern margin of the Tethys Ocean. Thirty rock cutting samples were collected from the Kharita Formation and analyzed for major and trace elements, total organic carbon, and palynological composition. These data, together with geophysical gamma ray log values and lithological composition, allowed us to reconstruct the changes in relative sea level at this time in the framework of a third-order transgressive-regressive (T-R) sequence stratigraphic model. Palynomorph composition, represented by a fairly diverse assemblage of terrestrial plant spores and pollen grains versus marine dinoflagellate cysts and other microplankton, was employed along with the variation in the particulate organic matter composition. Chemical proxies, including Si, Ti, and often K and Fe, and their ratios normalized to Al, as well as the carbonate content and the Sr/Ca ratio, provided significant stratigraphic variations with respect to sea-level changes. The above proxies allowed for the subdivision of the studied reservoir intervals into three T-R sequences.

The Middle Jurassic in the north Western Desert, Egypt, was a time of complex tectonics and increased environmental perturbations attributed to the predominant sedimentation of organic carbon-rich fine siliciclastic and carbonate deposits of the Khatatba Formation. Although some studies have addressed the hydrocarbon potential and source rock characteristics of the Khatatba Formation, a regional-scale investigation of the prevalent paleoenvironmental conditions and organic matter characteristics is still necessary. In this study, the Khatatba Formation is investigated for detailed palynofacies analysis and palynomorph composition to assess organic matter kerogen types and reconstruct the depositional paleoenvironmental patterns on a regional scale. For this purpose, 116 drill cuttings were collected from five wells in the Matruh, Shushan, and Dahab-Mireir Basins. Moderately diverse assemblages of spores, pollen, and dinoflagellate cysts are reported. Age-diagnostic dinoflagellate cysts, including Adnatosphaeridium caulleryi, Dichadogonyaulax sellwoodii, Korystocysta gochtii, Wanaea acollaris, and Pareodinia ceratophora, along with occasional records of Systematophora areolate and Systematophora penicillate, defined a Bajocian–Callovian age. Based on particulate organic matter (POM) composition, four palynofacies assemblages (PFAs) are identified. PFA-1 is the most common within the Khatatba Formation in the five studied wells. It contains high proportions of phytoclast fragments versus low contents of amorphous organic matter (AOM) and palynomorphs and is defined by a gas-prone kerogen Type III. PFA-2 is comprised of moderate abundances of AOM and phytoclast characteristics of oil-prone kerogen Type II. PFA-3 is dominated by phytoclasts and moderate to low proportions of AOM and palynomorphs of kerogen Type III, whereas PFA-4 consists of AOM and palynomorphs defining kerogen Type II. PFA-1 indicates predominant deposition in proximal active fluvio-deltaic sources to marginal marine conditions with enhanced contributions of terrestrial/riverine influx. PFA-2 and PFA-3 reveal deposition under an enhanced dysoxic to anoxic proximal inner neritic shelf due to the abundant occurrences of spores and coastal to shallow marine dinoflagellate cysts. PFA-4 suggests deposition under enhanced suboxic to anoxic distal inner neritic conditions because of enhanced AOM and abundant proximate and some chorate dinoflagellate cysts. Thus, the Middle Jurassic experienced a predominantly marginal to shallow water column in this part of the southern margin of the Tethyan Ocean where the Matruh, Shushan, and Dahab-Mireir Basins were located.

The Cretaceous Second White Specks Formation is an organic-rich marine mudstone rich in calcareous coccoliths and fecal pellets that form an immature oil shale deposit. Corehole and outcrop oil shale samples, taken from western Manitoba and across Saskatchewan, Canada, were analyzed by organic petrography (reflected white and UV light), Rock-Eval pyrolysis, and elemental analysis (boron and sulfur) to characterize the oil shales in relation to their depositional environment and hydrocarbon generating potential. This study revealed that the oil shales all contain small amounts of sapropelite/huminite and inertinite. Inertinite consists of particles deposited from a terrigenous environment and have higher %Ro > 0.4, referred to as secondary inertinite. Primary inertinite is associated with the roots of marine grass and seaweeds. Fluorescing marine telalginite, Nostochopsis alginite, dinoflagellates, liptodetrinite, matrix bituminite, and chlorophyllinite are also present. Based on a detailed geological, sedimentological, geochemical, and organic petrological investigation, the oil shales were divided into three depositional facies: coastal marine (B:60 ppm), shallow marine (B: ∼80 ppm), and open marine (B:113 ppm). The oil shales are immature (Tmax = 398–425 °C) across the entire study area with %Ro of 0.20–0.27. The coastal marine facies oil shales have high TOC content (ave. = 10.4 wt%), S2 ave. = 54.9 mg HC/g TOC, HI ave. = 480 mg HC/g TOC, low Boron (ave. = 47 ppm) content and can generate an average of 43 lit/tonne of hydrocarbons. On the other hand, the shallow marine facies oil shales have average TOC of 8.1 wt%, average S2 of 41.2 mg HC/g TOC, and are much higher in B content (ave. = 80 ppm). The open marine facies oil shales have low TOC (ave. = 0.94 wt%), S2 averages 1.3 mg HC/g TOC, and HI averages 189 mg HC/g TOC. They have much lower hydrocarbon potential (ave. = 1.50 lit/tonne) but are high in B content (ave. = 109 ppm). Overall, it was concluded that in one specific area in the Pasquia Hills of northeastern Saskatchewan, the Second White Specks oil shales are shallow (7 wt%, and can generate >80 lit/tonne of hydrocarbon. This makes them suitable for ex-situ extraction.

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...

Coal and interbedded rocks from the two coalfields in the southern intermontane region of British Columbia, Canada, deposited in fluvial-lacustrine, and lacustrine were examined using reflected lig...

The Devonian strata in the Western Desert of Egypt contain diverse plant and animal remains, in addition to the commonly reported miospores, acritarchs and chitinozoans. These remains are of signif...

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.

The combustion of fossil fuels from the input of oil refineries, power plants, and the venting or flaring of produced gases in oil fields leads to greenhouse gas emissions. Economic usage of greenhouse and flue gases in conventional and unconventional reservoirs would not only enhance the oil and gas recovery but also offers CO2 sequestration. In this regard, the accurate estimation of the interfacial tension (IFT) between the injected gases and the crude oils is crucial for the successful execution of injection scenarios in enhanced oil recovery (EOR) operations. In this paper, the IFT between a CO2/N2 mixture and n-alkanes at different pressures and temperatures is investigated by utilizing machine learning (ML) methods. To this end, a data set containing 268 IFT data was gathered from the literature. Pressure, temperature, the carbon number of n-alkanes, and the mole fraction of N2 were selected as the input parameters. Then, six well-known ML methods (radial basis function (RBF), the adaptive neuro-fuzzy inference system (ANFIS), the least square support vector machine (LSSVM), random forest (RF), multilayer perceptron (MLP), and extremely randomized tree (extra-tree)) were used along with four optimization methods (colliding bodies optimization (CBO), particle swarm optimization (PSO), the Levenberg–Marquardt (LM) algorithm, and coupled simulated annealing (CSA)) to model the IFT of the CO2/N2 mixture and n-alkanes. The RBF model predicted all the IFT values with exceptional precision with an average absolute relative error of 0.77%, and also outperformed all other models in this paper and available in the literature. Furthermore, it was found that the pressure and the carbon number of n-alkanes would show the highest influence on the IFT of the CO2/N2 and n-alkanes, based on sensitivity analysis. Finally, the utilized IFT database and the area of the RBF model applicability were investigated via the leverage method.

This study evaluates the palynologic, organic, inorganic, and petrographic properties of organic-rich black shale (Mahamid Mine) in the El Sebaiya area, Nile Valley, Egypt. Black shale is composed of quartz (50%), calcite (10%), kaolinite (25%) and montmorillonite (15%). Organic and inorganic analyses revealed that this shale was deposited under oxic to anoxic marine conditions during strong chemical weathering. Black shale has poor to very good organic richness, and poor to fair hydrocarbon potential. Organic petrography indicates that the kerogen is mixed types II/III and III and is immature to marginally mature (%VRo is 0.44 and 0.53). Liptinite macerals consist of alginite, cutinite, and bituminite. The hydrocarbon products to be generated at higher maturity are expected to be oil and gas.

Small angle neutron scattering (SANS) analysis was performed on six Bakken Shale samples with different maturities to reveal the complexities in the pore structure. Pore size distribution (PSD), porosity and specific surface area (SSA) were calculated from SANS data via the Polydisperse Spherical Pore (PDSP) model and compared with the data from N2 adsorption and mercury intrusion. The results showed that the Bakken samples have a very small porosity value (less than 1%) and a very larger specific surface area (larger than 180995 cm−1) in the measuring pore size range (pore diameter: 1–200 nm). SANS and N2 adsorption can detect pores in the similar size range (2–200 nm). The SSA measured by SANS and mercury intrusion was found larger than the one detected by N2 adsorption. Pore structure information that is obtained from SANS, N2 adsorption, and mercury intrusion methods exhibited a fractal and multifractal behavior. Moreover, the pore size distribution that is calculated from SANS data was the most heterogeneous. Finally, the effects of rock composition on pore structures demonstrated that organic matter hosts some isolated pores while clay minerals do not host a large quantity of pores that are either connected or isolated.

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.

The Jurassic–Early Cretaceous was a time of variable organic carbon burial associated with fluctuations of marine primary productivity, weathering intensity, and redox conditions in the pore and bottom water at paleo-shelf areas in north Egypt. This time interval characterized the deposition of, from old to young, the Bahrein, Khatatba, Masajid, and Alam El Bueib Formations in the north Western Desert. Although several studies have been devoted to the excellent source rock units, such as the Khatatba and Alam El Bueib Formations, studies on paleoenvironmental changes in redox conditions, paleoproductivity, and continental weathering and their impact on organic carbon exports and their preservation for this interval are lacking. This study presents organic and inorganic geochemical data for the Jurassic–Lower Cretaceous sediments from the Almaz-1 well in the Shushan Basin, north Western Desert. A total of 32 cuttings samples were analyzed for their major and trace elements, carbonates, and total organic carbon (TOC) contents. Data allowed the reconstruction of paleoenvironmental conditions in the southern Tethys Ocean and assessment of the changes in paleo-redox, paleo-weathering, and marine primary productivity, and the role of sediment supply. Additionally, factors that governed the accumulation of organic matter in the sediment were interpreted. Results showed that the Khatatba Formation was deposited during a phase of enhanced marine primary productivity under prevalent anoxia, which triggered enhanced organic matter production and preservation. During the deposition of the Khatatba Formation, significant terrigenous sediment supply and continental weathering were followed by a limited contribution of coarse clastic sediment fluxes due to weak continental weathering and enhanced carbonate production. The Bahrein, Masajid, and Alam El Bueib Formations were deposited during low marine primary productivity and prevalent oxygenation conditions that led to poor organic matter production and preservation, respectively. A strong terrigenous sediment supply and continental weathering predominated during the deposition of the Bahrein Formation and the lower part of the Alam El Bueib Formation compared to the limited coarse clastic supply and continental weathering during the deposition of the carbonate Masajid Formation and the upper part of the Alam El Bueib Formation. Such conditions resulted in the enhanced dilution and decomposition of labile organic matter, and, thus, organic carbon-lean accumulation in these sediments.

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.

Widespread deposition of pelagic-hemipelagic sediments provide an archive for the Late Cretaceous greenhouse that triggered sea level oscillations. Global distribution of dinoflagellate cysts (dinocysts) exhibited a comparable pattern to the eustatic sea level, and thus, considered reliable indicators for sea level and sequence stratigraphic reconstructions. Highly diverse assemblage of marine palynomorphs along with elemental proxies that relate to carbonates and siliciclastics and bulk carbonate &delta, 13C and &delta, 18O from the Upper Cretaceous Abu Roash A Member were used to reconstruct short-term sea level oscillations in the Abu Gharadig Basin, southern Tethys. Additionally, we investigated the relationship between various palynological, elemental, and isotope geochemistry parameters and their response to sea level changes and examined the link between these sea level changes and Late Cretaceous climate. This multiproxy approach revealed that a long-term sea-level rise, interrupted by minor short-term fall, was prevalent during the Coniacian-earliest Campanian in the southern Tethys, which allowed to divide the studied succession into four complete and two incomplete 3rd order transgressive-regressive sequences. Carbon and oxygen isotopes of bulk hemipelagic carbonates were calibrated with gonyaulacoids and freshwater algae (FWA)-pteridophyte spores and results showed that positive &delta, 13Ccarb trends were consistent, in part, with excess gonyaulacoid dinocysts and reduced FWA-spores, reinforcing a rising sea level and vice versa. A reverse pattern was shown between the &delta, 18Ocarb and gonyaulacoid dinocysts, where negative &delta, 18Ocarb trends were slightly consistent with enhanced gonyaulacoid content, indicating a rising sea level and vice versa. However, stable isotope trends were not in agreement with palynological calibrations at some intervals. Therefore, the isotope records can be used as reliable indicators for reconstructing changes in long-term sea level rather than short-term oscillations.

This study presents a high-resolution palynological analysis for the Abu Roash ‘A’ Member in the hydrocarbon-rich Abu Gharadig Basin, North Western Desert, Egypt. Thirty-one rock samples, spanning ...

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).

Carbon geo-sequestration (CGS), as a well-known procedure, is employed to reduce/store greenhouse gases. Wettability behavior is one of the important parameters in the geological CO2 sequestration process. Few models have been reported for characterizing the contact angle of the brine/CO2/mineral system at different environmental conditions. In this study, a smart machine learning model, namely Gene Expression Programming (GEP), was implemented to model the wettability behavior in a ternary system of CO2, brine, and mineral under different operating conditions, including salinity, pressure, and temperature. The presented models provided an accurate estimation for the receding, static, and advancing contact angles of brine/CO2 on various minerals, such as calcite, feldspar, mica, and quartz. A total of 630 experimental data points were utilized for establishing the correlations. Both statistical evaluation and graphical analyses were performed to show the reliability and performance of the developed models. The results showed that the implemented GEP model accurately predicted the wettability behavior under various operating conditions and a few data points were detected as probably doubtful. The average absolute percent relative error (AAPRE) of the models proposed for calcite, feldspar, mica, and quartz were obtained as 5.66%, 1.56%, 14.44%, and 13.93%, respectively, which confirm the accurate performance of the GEP algorithm. Finally, the investigation of sensitivity analysis indicated that salinity and pressure had the utmost influence on contact angles of brine/CO2 on a range of different minerals. In addition, the effect of the accurate estimation of wettability on CO2 column height for CO2 sequestration was illustrated. According to the impact of wettability on the residual and structural trapping mechanisms during the geo-sequestration of the carbon process, the outcomes of the GEP model can be beneficial for the precise prediction of the capacity of these mechanisms.

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.

This study addresses the stratigraphic and sedimentological characteristics of the Late Eocene carbonaceous shale-bearing Qasr El Sagha Formation in the Fayoum Basin, Egypt. The Qasr El Sagha succession is comprised of four facies types: coastal mudflat, tidal flat, swamp, and storm-affected tidal channels. The swamp facies contain the Fayoum carbonaceous shale facies, which have not been studied in the past. The present study reports the first publicly available sedimentological, palynological, and geochemical results for the Fayoum facies. Eight samples of the sequence were taken from a freshly exposed road cut and analyzed petrographically, geochemically, and palynologically in order to determine the paleoenvironment of deposition and prevailing conditions. The palynomorph assemblages show that the lower part of the sequence was deposited in a lowland-riparian environment with continued freshwater influx. The depositional regime in the upper part of the sequence was swampy and dominated by fresh water. Mixed angiosperms and pteridophytes dominated the woody forest vegetation and were the source for the formation of the Fayoum carbonaceous shale facies. The recovered palynomorph assemblage points to the prevalence of a tropical to a sub-tropical, warm, humid climate with heavy precipitation in the lowland, swampy areas that were in close proximity to the freshwater influx. The water table was above the fen surface, preventing oxidation of the vegetation. Intermittent flooding or fluctuation in paleo-water levels likely occurred in the peat paleo-mire. The Fayoum samples have Ro,ran values of ~0.40–0.50%, which is in very good agreement with the Tmax from Rock-Eval pyrolysis. Although a few of the samples have elevated S2 (15–24 mg HC/g rock) and HI values (125–140 mg HC/g TOC), they do not have any hydrocarbon generating potential in the sampled location as a result of their immaturity. Petrographically, the analyzed samples are dominated by huminite group macerals (up to 77%), with telohuminite (eu-eulminite B) being dominant. Liptinite content is up to 3.5%, whereas inertinite content is up to 6%, dominated by fungal sclerotia (funginite). The TOC of the facies samples does not exceed 40 wt%.