Amount Of Kerogen Research Articles

Formation mechanism of Gulong shale oil: Insights from semiclosed hydrous pyrolysis

As a typical lacustrine shale oil, Gulong shale oil has enormous resource potential. The current lack of understanding regarding the formation process of this oil has affected its development. This study uses a low-mature shale sample from the first member of the Qingshankou Formation in the Songliao Basin and analyzes the hydrocarbon generation, expulsion, and retention characteristics by conducting hydrous pyrolysis in a semiclosed system. The results show that the formation process of the Gulong shale oil can be divided into three stages. The slow hydrocarbon generation stage occurs when organic matter maturity (Ro) < 0.8 %, and only a small amount of hydrocarbons is generated by kerogen cracking. The products are mainly heavy components (C15+), with retained oil composing the majority of them. The rapid oil generation stage occurs when Ro is of 0.8 %–1.1 %, where a large amount of kerogen is cracked to generate hydrocarbons and reaches its peak when Ro is 1.1 %. Most of generated light component oil (C6–C14) is expelled, and retained oil is mostly composed of heavy components (C15+); Ro > 1.1 % indicates the stage of oil cracking and rapid gas generation. Light component oil (C6–C14) and gaseous hydrocarbons (C1–C5) are formed when heavy components oil (C15+) begins to crack. The light-to-heavy ratio of the hydrocarbon products (C1–C14/C15+) rapidly increases with maturity. The hydrous pyrolysis experiment in a semiclosed system is more in line with actual geological conditions of Qingshankou Formation compared to other experimental systems and can simultaneously consider the influence of geological factors such as temperature, pressure, hydrocarbon expulsion, and formation water.

Calculated and model profile of reservoir temperature during in-formation oxidation on the example of an oil field

The article describes physical and mathematical models of reservoir oxidation in oil deposits, the development of which is impossible with known technologies. In-formation oxidation is realized in the form of oil oxidation. A laboratory experiment on the core for the formation of combustion is presented, and the problems arising during the initiation of combustion in the rocks of the Bazhenov formation are described. It was revealed that the temperature gradient at the front and the rate of movement of the oxidation front are influenced by the volume of injected oxygen and the amount of kerogen per unit volume of the formation. The well-known Thomas model has been adapted for the analytical solution of the radial problem of in-situ combustion to the conditions of the implementation of oxidation processes in bituminous formations. The results of analytical calculations of the dynamics of changes in the formation temperature profile depending on the content of coking material and the flow rate of the injected air are presented. It was found that the temperature gradient at the front reaches 1,573 K/m, and that the rate of oxidation movement is influenced by the volume of oxygen and the density of kerogen reserves in the formation. Recommendations are made for further study of the advance of the front of intra-layer combustion in order to clarify the dependencies of the influence of other parameters (permeability, water saturation, etc.) on the speed of the front advance.

Investigation of the transformation of organic matter of carbonate deposits of the Semiluksky–Mendymsky horizon under hydrothermal conditions

The paper presents the results of studies on the transformation of the organic matter of siliceous-clayey carbonate rocks of the Semiluksko–Mendymsky horizon of the Romashkino oil field in a hydrothermal fluid for an hour (with a water-to-rock ratio of 33) at 340°C and 380°C and pressures of 17 and 20 MPa. As a result of hydrothermal treatment, at 340°C and 17 MPa, based on nitrogen porosimetry and electron microscopy data, transformations of rock-forming minerals in the rock are observed. They lead to an increase in the volume and average diameter of mesopores in it and the formation of micropores, as well, which improve its filtration properties. At the same time, the amount of kerogen in the composition of the organic matter decreases and the yield of the petroleum hydrocarbon extract increases, in which, according to the SARA analysis, the content of asphaltenes increases and the content of resins, aromatic and saturated hydrocarbons decreases. In the composition of aroatic hydrocarbons, the proportion of alkyltrimethylbenzenes and dibenzothiophenes increases, phenanthrene homologues appear, and in the composition of saturated hydrocarbons, the amount of iso-structure alkanes decreases relative to the content of linear alkanes. Raising the temperature and pressure of the hydrothermal fluid to 380°С and 20 MPa increases the degree of kerogen conversion from 12.4% to 23.6%. At the same time, changes occurring in the component composition of petroleum hydrocarbon extracts remains similar to the experiments carried out at 340°C and 17 MPa; the content of naphthalenes decreases, the content of dibenzothiophenes increases and C11–C17, C19–C22 alkyltrimethylbenzenes appear. According to IR spectroscopy, with increasing temperature and pressure of the hydrothermal fluid the intensity of the absorption bands of the aromatic ring, aliphatic fragments, and oxygen-containing groups increases in resins; the structural-group composition of asphaltenes changes little: aromaticity and the content of condensed structures slightly increase. The revealed distinctive features in the composition of organic matter after hydrothermal impact on siliceous-clayey carbonate rocks confirm the concept of staged destruction of kerogen, when large structural heteroatomic blocks (asphaltenes) are split off at the initial stages. Changes occurring in the composition of petroleum hydrocarbon extracts indicate their involvement in the process of hydrothermal transformation of organic matter of siliceous-clayey carmbonate rocks with the predominant reactions of dehydrogenation of naphthenic compounds and oxidative polycondensation of aromatic structures. The data of electron microscopy and nitrogen porosimetry of rocks after hydrothermal exposure at 380°С and 20 MPa indicate a deterioration in their reservoir properties. The most optimal thermobaric conditions of the hydrothermal fluid for the generation of petroleum hydrocarbons from kerogen of siliceous-clayey carbonate deposits of the Semiluksko–Mendymsky horizon of the Romashkino field, which improve their reservoir properties, are 340°С and 17 MPa; with implication of hard-to-recover heavy hydrocarbon resources and well-established catalytic methods of in-situ conversion.

Molecular Simulation of Methane Adsorption Capacity of Matrix Components of Shale.

Shale gas occurs mainly as adsorption and free gas. Among them, whether the adsorbed gas can be gradually desorbed or not is a major cause of stable and high yield. The matrix component is the main factor affecting the adsorption capacity of shale. In this paper, by simulation software named Materials Studio (MS), using Molecular Dynamics Simulation and Monte Carlo Simulation, the adsorption capacity of different matrix components under specific conditions is studied and the four models: relative concentration model, diffusion coefficient model, saturated adsorption capacity model and isosteric heat of adsorption model, are built. The simulation models show that the mineral matrix has a significant impact on the adsorption of methane molecules in shale: kerogen I &gt; smectite &gt; chlorite &gt; illite &gt; quartz. Kerogen I has the strongest adsorption capacity with high-density thick layer adsorption. Under the temperature (369.97 K) and the formation pressure (28.07 MPa) and under the condition of 6.0 nm in the cylindrical hole, excess adsorption amount of kerogen I is 13.418%, the diffusion coefficient is only 0.046 Å2/ps, saturated adsorption amount is 3.060 cm3/g, and the amount of adsorption heat is 9.598 kJ/mol. As the adsorption force on the pore wall is not as strong as the interaction repulsion force between adsorbents within a short distance, the clay minerals all have 2~4 layers of narrow layer and low-density adsorption. The adsorption thickness of the single layer is inversely proportional to its adsorption capacity, and the adsorption capacity is positively correlated with the opportunity of exposing oxygen atoms to form hydrogen bonds. Quartz has no obvious adsorption potential for methane molecules. This study is conducive to the quantitative evaluation of shale gas adsorption capacity, selection of favorable blocks and advantageous zones of shale gas reservoirs, and the improvement of development efficiency.

Petrophysics Evaluation for Determining Porosity of Shale Reservoirs

Indonesia is known for its large potential of shale resources, yet the character of their physical properties remains unclear. This study focuses on how to assess the petrophysical properties of shale using conventional wireline logs. Shale has been largely known as a host rock producing hydrocarbon in the conventional petroleum system due to the amount of kerogen trapped during the depositional process. The kerogen or continuously called Total Organic Carbon (TOC) behaves like a porosity to a density log and this will be misleading to the higher porosity than the actual shale rock. Prior investigation evaluates the physical properties in shale rock, including shale porosity, TOC, and matrix mineralogy, at a certain limited depth. A solid rock is presumed to consist of a shale matrix and TOC. Meanwhile, shale porosity is contained only in water. TOC responses to sonic wave, density, and porosity logs. We calculated the experimental data to estimate the volume of TOC at the limited depth to obtain the correlation of available logs. Shale porosity is then computed using a density log with the TOC-influence removed. The results show that the shale porosity is to be TOC-free with a value range of 3-14%.

ВИЗНАЧЕННЯ КІЛЬКОСТІ КЕРОГЕНУ, НЕОБХІДНОГО ДЛЯ ФОРМУВАННЯ РОДОВИЩ ВУГЛЕВОДНІВ ЗАХІДНОГО НАФТОГАЗОНОСНОГО РЕГІОНУ УКРАЇНИ

This paper considers the issue of determining the maximum hydrocarbons amount that can be generated by kerogen using thermodynamic methods. It is shown that the chemical composition of natural gas or gas condensate contains information about the generative capacity of kerogen from which it was formed. Based on experiments of type II and I kerogen pyrolysis and thermodynamic calculations by entropy maximization method, we propose a new method for determining the amount of kerogen from which gas was formed, which contains 1 dm3 of methane at a given ratio of butane isomers. The obtained data are interpreted as an indicator of kerogen maturity in the context of the depth of its destruction. This method is applied to theWestern oil and gas region of Ukraine hydrocarbon deposits. The analysis of kerogen transformations in the region sedimentary strata, using criteria of the GASTAR diagram, is carried out. We assessed the trends of kerogen conversion in the region in the areas of “maturity” and “biodegradation” in the ratio of ethane/propane (C2/C3) to ethane/isobutane (C2/i-C4). It is shown that the majority of deposits in the Western oil and gas region developed in the direction of maturation and only a small group of gas deposits – biodegradation. To establish the gases genesis in the region, we built a graph of the two geochemical indicators dependence – the methane/ethane ratio (C1/C2) and ethane/propane ratio (C2/C3). It is shown that some of the gas fields is formed due to the conversion of organic material of oil deposits. At the same time, gas condensate fields in the region, with few exceptions, are formed due to the primary destruction of kerogen. Based on the results of the calculations, maps of the methane (generated by type II kerogen) amount distribution were constructed. It is established that kerogen, which was the source material for hydrocarbon deposits of Boryslav-Pokuts oil and gas region, has practically exhausted its gas generation potential. Instead, kerogen from gas and gas condensate fields in the Bilche-Volytska oil and gas district still retains the potential to generate hydrocarbons.

Molecular and isotopic composition of modern soils derived from kerogen-rich bedrock and implications for the global C cycle

Ancient sedimentary organic matter (kerogen) represents the largest terrestrial organic carbon (OC) reservoir on earth and is vulnerable to remineralization upon exposure to earth’s atmosphere during the oxidative weathering of sedimentary rocks on the continents. Due to the potential for large carbon-cycle implications, the mechanisms and rates involved in kerogen transformation by oxidative weathering are becoming increasingly well-constrained in contemporary models of the global carbon cycle. Past field studies have focused primarily on areas where high erosion rates deliver large amounts of kerogen to earth’s surface, making the relative importance of low-lying landscapes a key unknown in regional or global scale estimates of kerogen recycling. The weathered residuum of organic-rich sedimentary rocks serves as the parent material for many soils. Therefore, some aspects of the chemical structure and biogeochemical cycling of the soil organic matter are likely to be inherited from the bedrock. We used a combination of solid-state 13C nuclear magnetic resonance (NMR) spectroscopy, and carbon isotope techniques to describe molecular and isotopic changes that occur throughout oxidative weathering of marine kerogens, and the subsequent formation of modern soils, in two outcropping Cretaceous mudstones of the Eagle Ford and Pepper Formations in central, Texas. Increasing production of oxygenated functional groups was coupled with reductions in characteristically abundant aliphatic components of marine kerogens along the weathering profiles. Organic matter structural parameters, derived from C–H dephasing NMR experiments, also provide the basis for a novel weathering index that accounts for the degree of post-sedimentary alteration of kerogen samples along the bedrock-soil continuum. An uncertain future marked by climatic shifts in temperature and/or precipitation and increased continental weathering and denudation rates highlights the potential for enhanced vulnerability of kerogen, and the need for molecular and isotopic tools for quantifying mechanisms and rates involved in kerogen weathering.

The mechanism of the terahertz spectroscopy for oil shale detection

Terahertz time domain spectroscopy (THz-TDS) can directly detect oil shales. The absorption coefficient is related to the oil content in the rock. This value can be compared across regions to measuring the oil content in the oil shale. Here we studied three regions and included scanning electron microscope (SEM) and thermogravimetric analysis (TGA) to verify the amount of kerogen within oil shale prior to the constitution of the mineral matrix via the THz response. Aromatic and the aliphatic compounds contribute to the absorption of shales in the THz range due to the relatively high intramolecular interactions—this reveals the mechanism of THz radiation penetration through shales as reported in previous reports. The differences in quantum structure of a molecule between organic and inorganic materials suggest that THz-TDS can be applied to geophysical prospecting and improve the effectiveness of the detection of organics in oil shale.

Porosity estimation in kerogen-bearing shale gas reservoirs

Porosity is a fundamental petrophysical parameter in shale gas reservoirs that governs the space for hydrocarbon storage, and directly determines the free gas amount and absorbed gas capability. Technically, in kerogen-bearing shales, well-log derived porosity may yield inaccurate results as the porosity tools in response to both the kerogen and the liquid-filled pore spaces that are often undifferentiated. In this paper, we propose a new method for porosity estimation in kerogen-bearing shales, where porosity is assumed to be composed of both matrix porosity and kerogen porosity. The kerogen responses of density, sonic and neutron logs are first calculated from experimental data to calibrate porosity logs with the kerogen volume. The matrix porosity is then computed using the improved Wyllie equation based on the calibrated logging data with the kerogen influence removed. The kerogen porosity is estimated by a mass-balance relation based on the original total organic carbon (TOCo) and kerogen maturity characterized by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Application of the new method to a shale gas reservoir in the Ordos Basin, China shows that the estimated porosity matches the core derived porosity satisfactorily well. Furthermore, the results also indicate that the shale kerogen porosity is relatively higher than the shale matrix porosity when the kerogen amount and maturity are high. The results of the study lead to a better understanding of the shale formation and thus contribute towards the better evaluation of shale gas reservoirs.

Evaluation of the shale beds within Alam El Bueib Formation as an unconventional reservoir, Western Desert, Egypt

Within Alam El Bueib Formation (AEB), thin sandstone beds of approximately 15.24 m (~50 ft) total thickness, are considered to be the main conventional hydrocarbon-producing zone in the Western Desert. However, the shale intervals within the AEB can be an unconventional reservoir target. In this study, we focus on evaluating these shale units through geochemical analysis, to determine the total carbon, total sulfur, total organic carbon (TOC), and Rock–Eval pyrolysis. TOC is an essential property needed to determine the productive shale gas play. Total organic carbon combined with other geochemical data is important in evaluating the potential of shale gas reservoirs as it is related to the amount of kerogen, the produced hydrocarbon content. The TOC in the studied samples indicates poor to very good organic continent, while the hydrocarbon potentiality (S1 and S2) indicates poor source potential. The hydrogen index reflected kerogen type III/II. These data indicate that AEB Formation may be considered as a good source for generating hydrocarbons (mainly gas with minor amount of oil). The maturation evaluated by using “Tmax” indicates immature to marginally mature source rock, and production index ‘‘PI” represents oil and gas production in case of maturation.

Total organic carbon evaluation of the Bowland Shale Formation in the Upper Bowland of the Widmerpool Gulf

Widmerpool Gulf is one of the basins in the carboniferous Bowland Hodder shale in Central Britain. The area of interest in the Widmerpool Gulf is the Bowland Shale Formation within the Upper Bowland. This paper focuses on evaluating the total organic carbon (TOC) from Rempstone 1 and Old Dalby 1 both penetrating the Bowland Shale Formation using Passey's delta Log R method. TOC is an essential property needed to have a productive shale gas play – accurate characterisation of TOC is critical in evaluating the potential of shale gas reservoirs because it closely relates to the amount of kerogen and therefore total gas content. Passey's method involves the use of well logs to obtain the organic richness i.e. TOC. It relies on the response of well logs to organic matter using an overlay of porosity logs and resistivity logs. Which causes a separation i.e. a delta Log R separation. The reasons for the delta Log R separation in an organic rich reservoir/non reservoir rocks is due to the presence of low density, high transit time kerogen and the presence of formation fluid i.e. oil, gas or water. Immature source rocks also observe a separation but only from the porosity log whilst non source rocks observe no separation. Rempstone 1 and Old Dalby 1 well logs were exported on Interactive Petrophysics to analyze the lithology of the intervals before been exported to Microsoft Excel to evaluate the parameters of Passey's equation to enable TOC determination. TOC estimates for the Upper Bowland Shale section in the Widmerpool Gulf and was found comparable to estimates obtained from British Geological Survey (BGS) RockEval core analysis report. This method proved to be a suitable way of estimating the total organic carbon using simple well logs.

셰일 저류층에서 케로젠, GOR 변화에 따른 속도 변화 및 AVO 반응 분석

Recently, the studies about rock physics model (RPM) in shale reservoir are widely performed. In shale reservoir, the degree of the maturity can be estimated by kerogen and GOR (Gas-Oil Ratio). The researches on the rock physics model of shale reservoir with the amount of kerogen have been actively carried out but not with GOR. Thus, in this study, we analyzed the changes in seismic velocity and density, and AVO (Amplitude Variation with Offset) response depending on changes in GOR and the amount of kerogen. Since the shale consists of plate-like particles, it has vertical transverse isotropy (VTI). Therefore we estimated the seismic velocity and density by using Backus averaging method and analyzed AVO responses based on these estimated properties. The results of analysis showed that the changes in the velocity with the GOR variation are small but the velocity changes with the variation in kerogen amount are relatively larger. In case, GOR 180 (Litre/Litre) which is boundary between heavy oil and light oil, when volume fraction of kerogen increased from 5% to 35%, the P-wave velocity normal to the layering increased 51%. That is, it helps estimating maturity of kerogen through the velocity. Meanwhile, when rates of oil-gas mixture are large, the effect of GOR variation on the velocity change became larger. In case volume fraction of kerogen is 5%, the P-wave velocity normal to the layering was estimated in heavy oil (GOR 40) but in light oil (GOR 300). The AVO responses analysis showed class 4 regardless of the GOR and amount of kerogen because variation of poisson`s ratio is small. Therefore, shale reservoir has possibility to have class 4.

Source rock characterization of the Albian Kazhdumi formation by integrating well logs and geochemical data in the Azadegan oilfield, Abadan plain, SW Iran

Abstract There are several source rock units in the Zagros Basin. Nevertheless, the Cretaceous Kazhdumi formation has presumably produced the majority of the commercial hydrocarbons in this area. The presence of organic matter rich and thermally mature rock units containing oil or gas prone kerogen is the key factor controlling the hydrocarbon generation potential. Owing to the lack of organic geochemical studies such a potential is poorly investigated in the Azadegan oilfield. In this study, firstly we investigate the lower Cretaceous Kazhdumi formation potential source rock based on geochemical parameters including type and amount of kerogen and thermal maturity, obtained from analyzing 45 cutting samples from 9 wells by using Rock-Eval 6 apparatus. Moreover, vitrinite reflectance measurements were carried out on 11 samples utilizing Zeiss Axioplan II microscope for further examination of the thermal maturation. Burial history analysis and thermal maturity modeling suggests that Kazdumi formation is marginally mature (vitrinite reflectance in the range of 0.5–0.7%) with hydrocarbon expulsion beginning since about 14 Ma. The results indicate increasing maturity from south to the north as a result of burial deepening of the Kazhdumi Formation. It contains type II and mixed types II/III kerogen with TOC (Total Organic Carbon) values up to 4.88 wt% and Source Potential Index (SPI) value of 3.72 t HC/m 2 providing a moderate source for the hydrocarbons encountered in the reservoir rocks. In the second part of this research, we attempt to characterize the Kazhdumi source rock by using intelligent systems. In this regard, a three-layered back-propagation Artificial Neural Network (ANN) with Levenberg–Marquardt (LM) training algorithm was designed to predict TOC values from well log data (RHOB, THOR, SGR, NPHI, DT). This network is capable of predicting TOC with correlation coefficient of 98.63% and 82.62% and MSE of 0.0067 and 0.1772 for training and testing steps, respectively. According to the ANN modeling and TOC distribution map, organic richness of the Kazhdumi formation increases from south to the north over the study area.

GIS-based geospatial infrastructure of water resource assessment for supporting oil shale development in Piceance Basin of Northwestern Colorado

Oil shale deposits of the Green River Formation (GRF) in Northwestern Colorado, Southwestern Wyoming, and Northeastern Utah may become one of the first oil shale deposits to be developed in the U.S. because of their richness, accessibility, and extensive prior characterization. Oil shale is an organic-rich fine-grained sedimentary rock that contains significant amounts of kerogen from which liquid hydrocarbons can be produced. Water is needed to retort or extract oil shale at an approximate rate of three volumes of water for every volume of oil produced. Concerns have been raised over the demand and availability of water to produce oil shale, particularly in semiarid regions where water consumption must be limited and optimized to meet demands from other sectors. The economic benefit of oil shale development in this region may have tradeoffs within the local and regional environment. Due to these potential environmental impacts of oil shale development, water usage issues need to be further studied. A basin-wide baseline for oil shale and water resource data is the foundation of the study. This paper focuses on the design and construction of a centralized geospatial infrastructure for managing a large amount of oil shale and water resource related baseline data, and for setting up the frameworks for analytical and numerical models including but not limited to three-dimensional (3D) geologic, energy resource development systems, and surface water models. Such a centralized geospatial infrastructure made it possible to directly generate model inputs from the same database and to indirectly couple the different models through inputs/outputs. Thus ensures consistency of analyses conducted by researchers from different institutions, and help decision makers to balance water budget based on the spatial distribution of the oil shale and water resources, and the spatial variations of geologic, topographic, and hydrogeological characterization of the basin. This endeavor encountered many technical challenging and has not been done in the past for any oil shale basin. The database built during this study remains valuable for any other future studies involving oil shale and water resource management in the Piceance Basin. The methodology applied in the development of the GIS based geospatial infrastructure can be readily adapted for other professionals to develop database structure for other similar basins.

Multi-scale Asymptotic Analysis of Gas Transport in Shale Matrix

Organic-rich resource shales play an important role in global natural gas production. However, many uncertainties exist in an engineering analysis of gas transport and production such as the reservoir-scale flow simulation, history-matching, and optimization. In this work, we introduce a new set of governing equations to describe the characteristic features of porous structures of the organic-rich resource shale. We apply multi-scale analysis to mass balance equations, the equation of state (for free gas), and an adsorption isotherm. Using the macroscopic model, we study gas transport in shales, consisting of nanoporous organic material (kerogen) and the inorganic material. We conclude that both gas in-place and gas production rate depend on the amount of kerogen in the shale matrix. Adsorbed-phase transport by the organic pore walls is responsible for the increase in production rate. We investigate both Henry and Langmuir adsorption as well as different values of length scale ratio and diffusion coefficients.

Diagenesis and kerogen release in oil- and gas-bearing shales

The microstructure of pore space in sedimentary rocks and its evolution during reaction with pore- or fracture-contained fluids is a critically important factor controlling fluid flow properties in geological formations, including the migration and retention of water, gases and hydrocarbons. The size, distribution and connectivity of these confined geometries (pores, fractures, grain boundaries), collectively dictate how fluids of various chemistries migrate into and through these micro- and nano-environments, wet, and ultimately react with the solid surfaces. In order to interpret the time-temperature-pressure-fluid flow history of any geological system, the physical and chemical "fingerprints" of this evolution preserved in the rock must be fully explored over widely different length scales from the nanoscale to the macroscale. We are experimentally investigating these reaction-controlled changes in rock microstructure by conducting in-situ heating experiments on samples of the Garfield oil shale. Oil shale, an organic-rich fine-grained sedimentary rock, contains significant amounts of kerogen (a solid mixture of organic chemical compounds) from which liquid hydrocarbons can be extracted. Pyrolysis (heating shale in the absence of oxygen) converts the kerogen in the oil shale to shale oil (synthetic crude oil) and oil shale gas and a solid residue. Through SANS, we clearly observe these kerogen and oxidation release at lower temperatures followed by pore structure reordering and finally enlargement at higher temperatures. These results are compared with preliminary results tracking the natural diagenesis of the commercially-important Eagle Ford shale formations across the oil/gas boundary.

The Mesozoic–Cenozoic organic facies in the Lower Tagus sub-basin (Lusitanian Basin, Portugal): Palynofacies and organic geochemistry approaches

Studies of the Mesozoic and Cenozoic sequence crossed by the Barreiro-4 borehole provide an improved understanding of the organic matter deposited in the Lower Tagus sub-basin (Lusitanian Basin, Portugal) and the implications for the potential source rock and depositional environment. This study focused on 43 samples (Middle Jurassic to Neogene) that were subjected to palynofacies and organic geochemistry analyses (Total Organic Carbon, Rock-Eval pyrolysis and molecular biomarker analysis). The palynofacies data indicate that the sequence contains mainly phytoclasts (non-opaque phytoclasts). However, the Middle Jurassic samples are dominated by Amorphous Organic Matter (AOM). Continental and/or marine palynomorphs are present in all the samples. The Cretaceous samples are characterized by small amounts of kerogen that have high contents of solid bitumen. The Total Organic Carbon (TOC) content is generally less than 1 wt.%. The Rock-Eval S1 and S2 parameters vary from 0.01 to 3.50 mgHC/g rock and 0.15 to 34.03 mgHC/g rock, respectively, with the highest values corresponding to the Cretaceous samples. The hydrogen index (HI) and oxygen index (OI) values range from 35 to 552 mgHC/g TOC and 4 to 180 mgHC/g TOC, respectively. The Tmax values range from 416 to 437 °C. The biomarker analysis showed that n-alkanes with 15–30 carbon atoms are present and usually have a unimodal distribution with a predominance of low to medium molecular weight compounds. The CPI values range between 0.63 and 3.65, and the pristane/phytane ratios vary between 0.48 and 1.64, indicating alternation of oxic–anoxic conditions along the sequence. The distribution of terpanes shows small amounts of tricyclic and tetracyclic terpanes in most of the samples (except for some Cretaceous samples) and a predominance of pentacyclic terpanes. The amount of 17α (H),22,29,30-trisnorhopane (Tm) usually exceeds the amount of 18α (H),22,29,30-trinorneohopane (Ts). The 20S/(20S + 20R) and αββ/(ααα + αββ) ratios of the C29 steranes generally have values below the range of equilibrium, indicating an immature stage of the OM.

Turning a Scientific Tool Into an Engineering Machine

Rock Tester Nobody knew where the oil and gas was trapped inside shale until a scanning electron microscope (SEM) showed the pores within the organic material inside. Now there are a growing number of machines creating three-dimensional (3D) digital replicas of these rocks by combining SEM imaging with a focused ion beam (FIBSEM), which cuts off ultra-thin slices like a meat slicer, revealing multiple layers within. These 3D digital images are incredibly detailed, but they are based on cubes whose longest side is 10–20 micrometers—millionths of a meter—making them small enough to fit into the spaces in porous sandstone. When it comes to building reservoir models, it leaves engineers wanting more. “The real challenge is we are creating micron-sized images and dealing with square miles of resources,” said Carl Sondergeld, a professor at the Mewbourne School of Petroleum and Geological Engineering at the University of Oklahoma (OU). “If we can transcend those scales we can do a better job of characterizing reservoirs.” In the pursuit of more, he and Chandra Rai, professor and director of the Mewbourne School, have built up one of the largest unconventional rock research laboratories, backed by 12 oil companies. The focus has been on understanding the workings of the nearly impermeable rocks, which has changed how some properties are measured. The large lab displays Sondergeld’s constant hunt for improved tools for analyzing how rocks and reservoirs perform. The laboratory recently added the latest generation of scanning electron micro-scopes from one of the biggest makers of these instruments, FEI. One thing that sets this FIBSEM machine apart is its ability to stitch together thousands of micron-scale images to create 2D pictures covering rock surfaces measured in millimeters rather than micrometers. These hyper-detailed pictures offer an overview of an area, with the option of zooming in for a closer look to see if low-resolution impressions are correct. They often are not. Another plus is its ability to create images using extremely low power—as low as a 100 V compared with 30,000 V for older machines—creating images that may offer better ways of measuring critical details, such as the amount of kerogen—the organic material that is the source of the oil and gas.

Source-rock seismic-velocity models: Gassmann versus Backus

Source rocks are described by a porous transversely isotropic medium composed of illite and organic matter (kerogen, oil, and gas). The bulk modulus of the oil/gas mixture is calculated by using a model of patchy saturation. Then, the moduli of the kerogen/fluid mixture are obtained with the Kuster and Toksöz model, assuming that oil is the inclusion in a kerogen matrix. To obtain the seismic velocities of the shale, we used Backus averaging and Gassmann equations generalized to the anisotropic case with a solid-pore infill. In the latter case, the dry-rock elastic constants are calculated with a generalization of Krief equations to the anisotropic case. We considered 11 samples of the Bakken-shale data set, with a kerogen pore infill. The Backus model provides lower and upper bounds of the velocities, whereas the Krief/Gassmann model provides a good match to the data. Alternatively, we obtain the dry-rock elastic moduli by using the inverse Gassmann equation, instead of using Krief equations. Four cases out of 11 yielded physically unstable results. We also considered samples of the North Sea Kimmeridge shale. In this case, Backus performed as well as the Krief/Gassmann model. If there is gas and oil in the shale, we found that the wave velocities are relatively constant when the amount of kerogen is kept constant. Varying kerogen content implies significant velocity changes versus fluid (oil) saturation.

Heavy Metals in Colorado and Chinese Oil Shale Semicoke: Disposal Issues, Impediments to Byproduct Conversion

Oil shale, a fine-grained sedimentary rock, contains a proportionally large amount of kerogen, which can be converted into oil by thermal degradation of the compacted rock. The primary byproduct of current oil shale oil extraction processes is semicoke. Its landfill deposition presents a possible threat to the environment and represents a waste of a potentially useable byproduct. In this work, we explore the heavy metal content of oil shale semicoke pyrolyzed at 500 and 1000 °C to better understand the risks posed by disposal of oil shale processing waste on the nearby environment, as well as impediments to potential byproduct conversion. The greatest potential obstruction to byproduct conversion and the greatest environmental risk posed by open air disposal of oil shale semicoke is likely due to relatively high arsenic concentrations; using X-ray fluorescence spectroscopy, we find arsenic concentrations in semicoke (pyrolyzed at 500 °C) ranging from 25 ppm for Chinese oil shale from the Huadian mine (class C) to 79 ppm for Green River, Colorado, 50 gallons per ton (GPT) of oil shale. Other heavy metal elements analyzed, including barium, copper, lead, manganese, and iron, are well below the United States Environmental Protection Agency (U.S. EPA) regional screening limits.