Kerogen Properties Research Articles

Predicting the Molecular Models, Types, and Maturity of Kerogen in Shale Using Machine Learning and Multi-NMR Spectra

Kerogen is the primary hydrocarbon source of shale oil/gas. The kerogen types and maturity are the two most crucial indicators that can reflect the hydrocarbon generation potential of shale oil/gas reservoirs. These indicators and the other mechanochemical properties can be effectively studied in a bottom-up strategy using kerogen molecular models. Thus, the rapid construction of kerogen molecular models is the cornerstone of shale oil/gas exploitation research. Because of the combinatorial explosion problem, there are two inherent disadvantages of traditional methods: being time- and material-consuming and labor-intensive. We propose a new method that combines machine learning with multiple nuclear magnetic resonance spectra to intelligently and with a high throughput predict the kerogen structures, types, and maturity. Neither the manual analysis of experimental spectra nor the enormous trial-and-error process is required in our method. The 650,000 groups of samples are annotated as the sample datasets. Various spectral types can be analyzed comprehensively using the multi-spectral form, and the predictive capability beyond that of the single input form is obtained. The results demonstrate that the average similarity of prediction molecules and the targets is 91.78%. The prediction accuracy of kerogen components, types, and maturity indexes is better than 92.4%, and the coefficients of determination R2 are all over 0.934. The results exhibit the excellent comprehensive performance and effectiveness of our method. Thus, we anticipate that this work will shorten the research cycle and tremendously reduce costs in constructing kerogen models and predicting kerogen properties.

Postdiagenetic Changes in Kerogen Properties and Type by Bacterial Oxidation and Dehydrogenation

A significant part of organic carbon found on the earth is deposited as fossil organic matter in the lithosphere. The most important reservoir of carbon is shale rocks enriched with organic matter in the form of kerogen created during diagenesis. The purpose of this study was to analyze whether the bacterial communities currently inhabiting the shale rocks have had any impact on the properties and type of kerogen. We used the shale rock located on the Fore-Sudetic Monocline, which is characterized by oil-prone kerogen type II. We were able to show that shale rock inhabited by bacterial communities are characterized by oxidized and dehydrated kerogen type III (gas-prone) and type IV (nonproductive, residual, and hydrogen-free). Bacterial communities inhabiting shale rock were dominated by heterotrophs of the Proteobacteria, Firmicutes, and Actinobacteria phyla. Additionally, we detected a number of protein sequences in the metaproteomes of bacterial communities matched with enzymes involved in the oxidative metabolism of aliphatic and aromatic hydrocarbons, which may potentially contribute to the postdiagenetic oxidation and dehydrogenation of kerogen. The kerogen transformation contributes to the mobilization of fossil carbon in the form of extractable bitumen dominated by oxidized organic compounds.

Termus shale of central Pahang, Malaysia: kerogen typing by palynofacies analysis

Palynofacies study has been done on selected samples fom the Late Jurassic – Early Cretaceous Termus Shale from Kuala Tahan, Jerantut-Jengka and Maran in Central Pahang to study its kerogen properties. Palynofacies study reveals distinct organic matter composition of different biological affinities from the samples where the organic matter composition were sorted into maceral groups and then by its distribution, to standard kerogen types. Three types of kerogens were interpreted: kerogen Type I, kerogen Type III and kerogen Type IV. Kerogen Type I and Type IV is interpreted in Kuala Tahan, Type III in Jerantut and kerogen Type III and Type IV are interpreted in the Maran area. The overall kerogen types correspond to different hydrocarbon potential ranging from high-low oil and gas potential.

Robust determination of kerogen properties in organic-rich mudrocks via Raman Spectroscopy

Organic-rich mudrocks are an expansive resource of hydrocarbons that support the global energy demand. Effective characterization and appraisal of these resources relies upon accurate volumetric quantification of organic phases in the formation, which include producible hydrocarbons (oil and gas) and an abundant, nonproducible, insoluble solid (kerogen). A substantial uncertainty in this volumetric quantification comes from the variable, and nearly always unknown, composition and properties of kerogen. This paper demonstrates a novel method to quantify relevant properties of type II kerogen in organic-rich mudrocks from Raman spectroscopy measurements of bulk samples. The correlations are developed using a geographically and geologically diverse set of organic-rich mudrocks containing type II kerogens, with ages spanning more than 200 Ma and hydrocarbon generation stages ranging from immature to dry gas. The properties comprise kerogen’s carbon mass fraction, density, hydrogen index, apparent thermal neutron porosity, and macroscopic cross section for thermal neutron capture. These properties are estimated from empirical correlations between these kerogen property values quantified by laboratory reference techniques and kerogen spectral characteristics quantified from Raman measurements. The Raman-based method is a practical alternative for quantification of kerogen properties that are critical for the correct interpretation of common wellbore logging measurements made in organic-rich mudrocks.

Mechanical response of kerogen at high strain rates

As the main organic component of shale, the kerogen has a direct impact on the shale reservoirs. A molecular aggregate is used to study mechanical behaviour of kerogen, of which the molecular weight distribution is rational conforming to the Gaussian distribution. The mechanical response of kerogen is obtained with different strain rates by using molecular dynamics simulations. The results show that kerogen shows material hardening and fracture strain decrease with the strain rate. In the plastic range, we analyse the causes of stress oscillation at the microscopic level, and obtain the relationship between the stress oscillation and hydrogen bond. A compressible hyper-viscoelastic constitutive model of kerogen is established, which describes the mechanical behaviour of kerogen with different strain rates. Our research provides a valuable insight in the kerogen properties, and helps to understand the mechanical behaviour of shale reservoirs from a micro-perspective.

Petrophysics of Kerogens Based on Realistic Structures.

Combining hydraulic fracturing with lateral drilling has allowed for economical hydrocarbon production from unconventional formations. Nevertheless, beyond hydraulic fracturing, our understanding of how hydrocarbons are stored and transported from the stimulated volume of a reservoir is still limited. Source rocks consist of organic materials finely dispersed within an inorganic matrix. Despite their small size, these organic pockets are capable of storing significant amounts of hydrocarbon due to their large surface area. The extent of the source rock’s storage capacity is determined by several factors, including the natural fracture abundancy, organic material content, type, and level of maturity. The petrophysical properties of organic materials, also known as kerogens, are subject to a high degree of uncertainty. Kerogens are difficult to isolate experimentally, which hinders accurate petrophysical analysis. The objective of this research was to use a molecular modeling approach to explore the petrophysical characteristics of kerogen. Kerogen macromolecules of different types and maturity levels were recreated via a computational platform. Then nanoporous structures representing these kerogens were obtained and characterized. Several elemental parameters, including porosity, density, pore size distribution, and adsorption capacity were closely delineated. The kerogen properties were found to correlate with the kerogen type and thermal maturity level. Kerogen type III showed the highest storage capacity, followed by types II and I, in a descending order. Moreover, in the same type of kerogen, a general trend of increasing storage capacity was observed as the maturity level increased. Methane adsorption capacity was modeled as a function of kerogen porosity. A transition flow regime was found to be the predominant mechanism. Such observations have significant implications for reservoir-scale modeling of unconventional resources.

Shale gas reservoir modeling and production evaluation considering complex gas transport mechanisms and dispersed distribution of kerogen

Stimulated shale reservoirs consist of kerogen, inorganic matter, secondary and hydraulic fractures. The dispersed distribution of kerogen within matrices and complex gas flow mechanisms make production evaluation challenging. Here we establish an analytical method that addresses kerogen-inorganic matter gas transfer, dispersed kerogen distribution, and complex gas flow mechanisms to facilitate evaluating gas production. The matrix element is defined as a kerogen core with an exterior inorganic sphere. Unlike most previous models, we merely use boundary conditions to describe kerogen-inorganic matter gas transfer without the instantaneous kerogen gas source term. It is closer to real inter-porosity flow conditions between kerogen and inorganic matter. Knudsen diffusion, surface diffusion, adsorption/desorption, and slip corrected flow are involved in matrix gas flow. Matrix-fracture coupling is realized by using a seven-region linear flow model. The model is verified against a published model and field data. Results reveal that inorganic matrices serve as a major gas source especially at early times. Kerogen provides limited contributions to production even under a pseudo-steady state. Kerogen properties’ influence starts from the late matrix-fracture inter-porosity flow regime, while inorganic matter properties control almost all flow regimes except the early-mid time fracture linear flow regime. The contribution of different linear flow regions is also documented.

Characterization and range of kerogen properties in the Vaca Muerta Formation, Neuquén Basin, Argentina

The Vaca Muerta Formation of the Neuquén Basin, Argentina, is a prolific oil- and gas-producing resource, characterized by high organic content and a large thermal maturity gradient running east to west. Kerogen properties are expected to vary substantially across the basin because of the range in thermal maturity (immature to dry gas). A comprehensive dataset of kerogen properties comprising thermal maturity, elemental composition, skeletal density, and specific surface area was acquired on cores from six wells. Kerogen isolates were prepared using a novel combination of acid demineralization and critical point drying that preserves the chemical and microstructural characteristics of kerogen. Kerogen properties are found to differ substantially between the studied wells, with variations correlating with thermal maturity. Kerogens show decreasing hydrogen content (H/C ratio ∼0.9–0.4) and nuclear hydrogen index (∼0.75–0.45), increasing grain density (∼1.28–1.55 g/cm3), and increasing surface area (∼100–350 m2/g) during maturation. These properties can dominate the response of logging tools run in organic-rich mudrocks and are needed to properly interpret downhole logs run therein for appraisal of porosity, hydrocarbon volumes, and total hydrocarbon-in-place, for example.

Integrating Measured Kerogen Properties With Log Analysis for Petrophysics and Geomechanics in Unconventional Resources

Integrating Measured Kerogen Properties With Log Analysis for Petrophysics and Geomechanics in Unconventional Resources

The impact of kerogen properties on shale gas production: A reservoir simulation sensitivity analysis

Gas shales are complex materials with transport occurring over many length scales, from relatively large systems such as natural and induced fractures to relatively small systems including kerogen-hosted pores of nearly molecular size. Here we present results of a sensitivity analysis performed using reservoir simulation designed to test how these different pore space length scales impact gas production. The shale is modeled as a triple porosity system comprising: first, natural and induced fractures; second, kerogen-hosted pores of approximately 25 nm diameter (as are typically observed in SEM images); and third, kerogen-hosted pores of approximately 1 nm diameter (which are below the size detectable by SEM but are typically observed in X-ray diffraction and gas adsorption experiments). In these simulations, the smaller kerogen-hosted pores act as a source term, releasing primarily adsorbed gas. The larger kerogen-hosted pores contribute to storage and transport, serving both as a source of gas on their own and a system through which the gas originating in the smaller pores can flow. As a result, the volume of the smaller pores impacts mainly the later production, when the reservoir pressure is near or below the Langmuir pressure. The volume of the larger pores impacts mainly the early stage of production, when mainly free gas is being produced. The radius of the smaller pores impacts the late stage of production, as smaller pores have greater surface area and therefore larger Langmuir volume. The radius of the larger pores has little impact on the ultimate recovery but instead impacts the production rate, as larger pores correlate with greater permeability. The results suggest that measurements of the variation of kerogen properties—performed potentially using cuttings, cores, or logs—can be used to refine parameters in reservoir simulations.

Beyond dual-porosity modeling for the simulation of complex flow mechanisms in shale reservoirs

The state of the art of modeling fluid flow in shale reservoirs is dominated by dual-porosity models which divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive micro- and nano-pore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual-porosity models and Darcy’s law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of the complex flow mechanisms occurring in these reservoirs. This paper presents a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three porosity systems: inorganic matter, organic matter (mainly kerogen), and natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of nano-pores and micro-pores in kerogen are incorporated into the simulator. The multiple-porosity model is built upon a unique tool for simulating general multiple-porosity systems in which several porosity systems may be tied to each other through arbitrary connectivities. This new model allows us to better understand complex flow mechanisms and eventually is extended into the reservoir scale through upscaling techniques. Sensitivity studies on the contributions of the different flow mechanisms and kerogen properties give some insight as to their importance. Results also include a comparison of the conventional dual-porosity treatment and show that significant differences in fluid distributions and dynamics are obtained with the improved multiple-porosity simulation.

Pore-scale modeling and analysis of surface diffusion effects on shale-gas flow in Kerogen pores

This paper investigates the influences of surface diffusion on shale-gas transport through our proposed model. The model simulates multiple flow mechanisms in Kerogen pores considering surface diffusion, its impact on slippage velocity, and nonlinear assembly of viscous flow and Knudsen diffusion contribution. Further, an improved gas slippage model was developed considering the additional viscous flux produced by surface diffusion. A sensitivity analysis was carried out using real Kerogen properties to identify the contributions of surface diffusion to gas permeability. The results show that surface diffusion gradually becomes a primary contributor to gas production with decreasing pore pressure and pore diameter and increasing surface diffusivity and adsorbed capacity of Kerogen. In particular, surface diffusivity and pore diameter are the two most important factors for surface diffusion. However, the importance of surface diffusion is only valid in the cases satisfying certain conditions. In this study, the influence of surface diffusion becomes strong and must be accounted for when the surface diffusivity exceeds 1E-7 m2/s and the pore diameter is less than 5 nm.

Organic matter characteristics and gas generation potential of the Tertiary shales from NW Kutch, India

Abstract Geochemical attributes of shale such as the TOC content, thermal maturity and kerogen properties provide useful insights on its gas generation potential. Here, the Tertiary shales interbedded within the lignite sequences of Naredi Formation in North Western Kutch Basin have been studied to understand the abundance, thermal maturity and quality of kerogen in the shale׳s organic matter. The samples have been collected from the opencast mines of Matanomadh, Panandhro and drill site of Umarsar, where the Naredi Formation is exposed. Open system pyrolysis of the Tertiary shales was carried out using the Rock Eval 6 pyrolyser. The results show the S1 (free hydrocarbons) and S2 (hydrocarbons cracked from kerogen) values to range between 0 and 3.71 mg HC/g rock and 0.02 and 91.13 mg HC/g rock respectively. The Tmax (temperature at the highest yield of S2) ranges between 383 and 452 °C. The Total Organic Carbon (TOC) content varies between 0.35% and 30.92% and the hydrogen index (HI) values lie between 3 and 358 mg HC/g TOC. In general the shales, particularly the subsurface cores from Matanomadh and Umarsar indicate very good to excellent organic richness. Based on the hydrogen and oxygen indices, the organic matter is characterized by Type-II and Type-II/III kerogen. The variation of HI vs Tmax suggests immature stage for the generation of hydrocarbons. The shales interbedded within the Naredi Formation can have high potential for gas generation in areas where the formation is buried deeply and has attained sufficient thermally maturity to generate the gas.

Gas potential of Proterozoic and Phanerozoic shales from the NW Himalaya, India: Inferences from pyrolysis

Organic richness and kerogen properties of sixty-seven shales, obtained from the outcrops and underground mines of Jammu, Kashmir and Ladakh regions of Northwest Himalaya, India, have been studied to evaluate their gas generation potential using Rock Eval pyrolysis. Ranging in age from the Proterozoic to Tertiary, organic matter content and characteristics of the carbonaceous and coaly shales vary widely, indicating that sedimentary and burial history significantly affected the preservation and maturation of organic components in rocks.The total organic carbon (TOC) content ranges from 0.01 to 1.2% in the Permian–Jurassic and Paleozoic–Tertiary shales of Ladakh to as high as 32.5% in the Eocene shales/coaly shales from Jammu. The thermo-labile hydrocarbons (S1) and those from cracking of kerogen (S2), released from the pyrolysis of Eocene Subathu shales, are observed to be high (from 0.1 to 2.6 and from 0.5 to 15.5mgHC/g rock, respectively). Rock Eval thermal maturity parameters, indicated by Tmax (temperature at highest yield of S2; >490°C) and calculated vitrinite reflectance (1.5 to 3.7 Ro %), suggest a post-mature, dry gas stage for the hydrocarbon generation. Based on hydrogen index (HI) and Tmax correlations, organic matter in the Subathu shales is characterized by a late metagenetic gas prone Type III kerogen and a fair to excellent gas potential is exhibited by these shales.The interbedded shale units in the Proterozoic Sirban Limestone Formation, occurring as an isolated inlier in Jammu, show TOC values from 0.1 to 1.4% with quite low S1, S2 and HI values. Thermal maturity of shales within the stromatolitic Sirban succession indicates a post-mature and/or already spent hydrocarbon stage. The Plio-Pleistocene carbonaceous clays, lignites and mudstones from the Lower Karewa Group of Kashmir basin are organically rich with TOC content ranging from 5.86 to 29.4%. A thermally immature, Type II/Type III kerogen is indicated by the HI (109 to 278mgHC/g TOC) and Tmax (399 to 427°C) plots of the Karewa samples. The exposed Lower Triassic Black shales from the Permian–Triassic boundary sections in Kashmir are comparatively lean in organic matter, with TOC values ranging from 0.18 to 0.93%, whereas the Permian–Jurassic and Paleozoic–Tertiary shales from Ladakh have a TOC content ranging from 0.01 to 1.22%. The pyrolyzable organic carbon is <0.1% and the residual organic carbon contributes significantly to the TOC content of these shales. The other Rock Eval parameters (S1, S2, HI) are quite low and indicate a poor source potential. The majority of shales from the Tethys and Trans Himalayan regions appear to have undergone metamorphism and exhumation of organic carbon associated with the Himalayan orogeny.

Inversion-based method for estimating total organic carbon and porosity and for diagnosing mineral constituents from multiple well logs in shale-gas formations

Reliable estimates of petrophysical and compositional properties of organic shale are critical for detecting perforation zones or candidates for hydro-fracturing jobs. Current methods for in situ formation evaluation of organic shale largely rely on qualitative responses and empirical formulas. Even core measurements can be inconsistent and inaccurate when evaluating clay minerals and other grain constituents.We implement a recently introduced inversion-based method for organic-shale evaluation from conventional well logs. The objective is to estimate total porosity, total organic carbon (TOC), and volumetric/weight concentrations of mineral/fluid constituents. After detecting bed boundaries, the first step of the method is to perform separate inversion of individual well logs to estimate bed physical properties such as density, neutron migration length, electrical conductivity, photoelectric factor (PEF), and thorium, uranium , and potassium volumetric/weight concentrations. Next, a multilayer petrophysical model specific to organic shale is constructed with an initial guess obtained from conventional well-log interpretation or X-ray diffraction data; bed physical properties are calculated with the initial layer-by-layer values. Final estimates of organic shale petrophysical and compositional properties are obtained by progressively minimizing the difference between calculated and measured bed properties. A unique advantage of this method is the correction of shoulder-bed effects on well logs, which are prevalent in shale-gas plays. Another advantage is the explicit calculation of accurate well-log responses for specific petrophysical, mineral, fluid, and kerogen properties based on chemical formulas and volumetric concentrations of minerals/kerogen and fluid constituents.Examples are described of the successful application of the new organic-shale evaluation method in the Haynesville shale-gas formation. This formation includes complex solid compositions and thin beds where rapid depth variations of mineral/fluid constituents are commonplace. Comparison of estimates for total porosity, total water saturation, and TOC obtained with (a) commercial software for multimineral analysis, (b) our organic-shale evaluation method, and (c) core/X-ray diffraction measurements indicates a significant improvement in estimates of total porosity and water saturation yielded by our interpretation method. The estimated TOC is also in agreement with core laboratory measurements.

Source Rock Quality Determination from Oil Biomarkers I: A New Geochemical Technique

Biomarker analyses of the Aspen Shale (Mowry Shale equivalent), Skully's Gap, Wyoming, suggest that vital source rock properties (e.g., kerogen hydrogen-to-carbon [H/C] ratio, Rock-Eval Hydrogen (HI), and maceral composition) may be indirectly, yet quantitatively, predicted from the biomarker parameters measured in oils. A strong correlation exists between the Homohopane Index of Aspen source rock extracts and both the H/C ratio and HI of the associated kerogen (R2 = 0.93 and 0.83, respectively). The percentages of C30 and C28 4-desmethyl steranes, relative to total extracted 4-desmethyl steranes, correlate with the percentage of marine-derived amorphous type II organic matter in the kerogen (R2 = 0.80 and 0.73, respecti ely), and with kerogen H/C ratio and HI (R2 = 0.89 and 0.88, respectively, for C30 steranes; R2 = 0.89 and 0.83, respectively, for C28 steranes). The ratio of 4^agr-methyl-24-ethylcholestanes to 3s-methyl-24-ethylcholestanes in the extracts also correlates with kerogen H/C ratio and HI (R2 = 0.93 and 0.92, respectively). In contrast, the percentage of C29 steranes in the extracts correlates with the percentage of higher-plant-derived vitrinite in the kerogen (R2 = 0.69), and shows a negative correlation with H/C ratio and HI (R2 = 0.81 and 0.66, respectively). These relationships were used to determine indirectly the source rock kerogen properties of several Mowry-derived oils. The correlations etween biomarkers and source rock properties observed in the Aspen Shale probably apply to many deltaic and nearshore marine source rocks that were deposited after the evolution of vascular plants. Therefore, prediction of source rock properties from oils in vertically drained basins could prove extremely useful to explorationists seeking to identify the most oil-prone areas in regions such as the U.S. Gulf Coast, the North Sea, the Beaufort Sea, and the Mahakam and Niger deltas. An example from the Beaufort Sea is given in this same issue (McCaffrey et al., 1994).