Conversion Of Kerogen Research Articles

High sulphur oil of Type II kerogen of the oil shales from Western Central Jordan based on molecular structure and kinetics

Organic rich sedimentary rocks of the Late Cretaceous Muwaqqar Formation from the Lajjun outcrop in the Lajjun Sub-basin, Western Central Jordan were geochemically analyzed. This study integrates kerogen microscopy of the isolated kerogen from 10 oil shale samples with a new finding from unconventional geochemical methods [i.e., ultimate elemental (CHNS), fourier transform infrared spectroscopy and pyrolysis–gas chromatography (Py–GC)] to decipher the molecular structure of the analyzed isolated kerogen fraction and evaluate the kerogen composition and characteristics. The optical kerogen microscopy shows that the isolated kerogen from the studied oil shales is originated from marine assemblages [i.e., algae, bituminite and fluorescence amorphous organic matter] with minor amounts of plant origin organic matter (i.e., spores). This finding suggests that the studied kerogen is hydrogen-rich kerogen, and has the potential to generate high paraffinic oil with low wax content. The dominance of such hydrogen-rich kerogen (mainly Type II) was confirmed from the multi-geochemical ratios, including high hydrogen/carbon atomic of more than 1.30 and high A-factor of more than 0.60. This claim agrees with the molecular structure of the kerogen derived from Py–GC results, which suggest that the studied kerogen is mainly Type II-S kerogen exhibiting the possibility of producing high sulphur oils during earlier stages of diagenesis, according to bulk kinetic modeling. The kinetic models of the isolated kerogen fraction suggest that the kerogen conversion, in coincidence with a vitrinite reflectance range of 0.55–0.60%, commenced at considerably lower temperature value ranges between 100 and 106 °C, which have produced oils during the early stage of oil generation. The kinetic models also suggest that the commercial amounts of oil can generate by kerogen conversion of up to 50% during the peak stage of oil window (0.71–0.83%) at relatively low geological temperature values in the range of 122–138 °C. Therefore, further development of the Muwaqqar oil shale successions is highly approved in the shallowly buried stratigraphic succession in the Lajjun Sub-basin, Western Central Jordan.

Phase behavior and GOR evolution using a natural maturity series of lacustrine oil-prone shale: Implications from compositional modelling

For the exploration of shale oil, there is still an urgent need to relate hydrocarbon generation reactions and changing phase behavior to exact levels of thermal maturity. Six organic-rich shale samples from the Cretaceous Qingshankou Formation, Songliao Basin spanning the maturity range with vitrinite reflectance (Ro) 0.58%–1.16% were studied for petroleum generation characteristics using the PhaseKinetics, PhaseSnapshot, and GORFit approaches. All samples show very good petroleum potential and contain Type I kerogen with total organic carbon contents ranging between 1.5% and 5%. A full spectrum of light to heavy hydrocarbons, consistent with live oils, occurs in thermal extracts of all samples. Gas chromatography fingerprints of samples with Ro > 0.7% closely resemble waxy oils derived from lacustrine organic matter (OM); fingerprints of lower maturity samples are not yet as wax rich. The inferred petroleum type organofacies of all samples is paraffinic high wax with low organic sulfur levels. Hydrocarbon generation from the least mature sample is characterized by one dominant activation energy at 55 kcal/mol, accounting for 87% of the total bulk reaction. Assuming a simplified geological scenario, i.e., a 3 K/My linear heating rate, primary petroleum is generated (transformation ratio, i.e., TR: 10%–90%) over a narrow temperature interval of only 23 °C. Onset (10% TR), maximum (Tpeak), and completion (90% TR) temperatures and Ro values are 141 °C at Ro 0.85%, 155 °C at Ro 1.08%, and 164 °C at Ro 1.2%, respectively. Primary gas generation (148–172 °C) occurs 10 °C later (300 m deeper) than the generation of C6+ compounds (138–161 °C). Secondary gas formation from oil cracking begins at 182 °C, maximizes at 197 °C, and is completed well before 225 °C (beginning of late gas generation from the secondary cracking of thermally matured, macromolecular organic matter) at 206 °C. Thus, primary and secondary oil cracking processes do not overlap under geological conditions. In line with a paraffinic high-wax oil petroleum type organofacies, cumulative fluids generated from the least mature sample fall within the black oil class over most of the primary kerogen conversion range up to 90% TR as indicated by low saturation pressures (Psat) and gas-oil-ratios generally below 160 Sm3/Sm3. Maturation results in relatively heavy fluids with Psat values in the range 40–70 bar when the free hydrocarbons, i.e., already present prior to pyrolysis, are included, and in lighter fluids with Psat values in the range 70–90 bar, when the free, mostly waxy hydrocarbons, are excluded. Systematics of physical properties and fluid compositions evolution reproduce the general behavior of naturally occurring petroleum sourced from lacustrine OM very well and fit physical properties and compositions of produced shale oils in the Songliao Basin at comparable maturity levels.

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.

Log scale rock physics modelling to study the effect of mineralogy on elastic properties of the Bakken Formation

The Bakken Formation is a geographically extensive, organic-rich, tight formation in the Williston Basin and currently serves as the second largest producer of oil in the USA. With respect to stratigraphy, the Devonian–Mississippian-age Bakken Formation typically comprises three members: the Upper (UB), Middle (MB), and Lower Bakken (LB). Lithologically, the upper and lower members of the Bakken are dominated by shales rich in organic-carbon, which act as the source rock for oil reservoirs in the Middle Bakken. The lithology of the Middle Bakken varies widely from siliciclastic to carbonates, with multiple distinct lithofacies typically being identified in the North Dakota portion of the Williston Basin. Good knowledge of the rock properties of the various Bakken members and lithofacies are a key component of their production potential.This study is a continuation of earlier rock physics modelling, which was done at core scale. Data from one well in Mountrail County was used for estimation of rock stiffness and velocities. Rock physics models were developed at log scale to obtain knowledge of formations' elastic properties across the Bakken members, as a function of porosity and pores' fluid type and geometry. Furthermore, the effect of frequency on fluid mixing type was investigated using both homogeneous and patchy models, then fluids were incorporated into the inclusion system using K-T, DEM, or Gassmann's equations. Kerogen was added to the system as a part of the inclusion in a way that fluid was embedded into the organic-matter. Critical porosity of 30% was also applied during DEM modeling to investigate the effects of kerogen being the load-bearing and rock matrix being suspended into it for case of high kerogen content in thermally immature source-rocks. The UB and LB shales, due to the presence of clay minerals, showed lower properties than MB and composed mainly of microfracture pores. Furthermore, the conversion of kerogen into hydrocarbons lowers the overall rock properties of the Bakken shales. The MB siliciclastic intervals showed to have more of intraparticle pores (primary porosity) with stiffer properties, whereas carbonate zones exhibited fracturing (secondary porosity). The rock physics models at macro and log scale complement each other and present a full picture of formations' elastic properties. The estimated stiffness and velocity properties are valuable input data for the development of and production from future wells.

Thermal conductive proppant with self-suspension ability

The insitu mining technology is applied to the exploitation of medium- and low-maturity shale oil, which can use heaters to warm up the oil shale formations and pyrolyze the kerogen. Due to the low thermal conductivity of oil shale, electric heaters need extra equipment to improve heat transfer efficiency. In this study, a thermally conductive proppant is fabricated by coating epoxy-resin and graphite on ceramic proppants for the first time, which could support the fracturing crack and transfer heat. The thermal conduction property of epoxy-resin and graphite coated proppants (EGPs) is 245% higher than that of uncoated proppants, which can transfer more heat to the oil shale formation and accelerate the conversion of kerogen. The adhesive property of EGPs is improved by 47.9% under the load force of 1500 nN, which prolongs the time for the fracture to close. In summary, this novel proppant is expected to assist in-situ mining technology in the production of medium and low-maturity shale oil.

Geochemical investigation and basin modelling of the Al renk shale formation in the Melut Basin, south Sudan: Implications for estimation of thermogenic gas generation potential

This study uses organic geochemical and basin modelling results to examine the potential for thermogenic gas generation from oil-to-gas conversion of the organic-rich Lower Cretaceous Al Renk shales in the Melut Basin, South Sudan. The overall geochemical results show that the Al Renk shales are considered good gas-source rocks with total organic carbon (TOC) content >1 wt % and a low hydrogen index (i.e., HI < 150 mg HC/g TOC; mainly Type III kerogen). This finding contrasts with the source of organic matter and biomarkers related to the depositional environment. Based on biomarker indicators, the Al Renk shales contains a mixture of aquatic organic matter with some terrigenous land plants and was deposited under suboxic to relatively oxic settings in a lacustrine environment. The presence of mixed aquatic and terrigenous organic matter in lacustrine shale sediments suggests a mix of Types II and III kerogen as the original organic matter input during deposition. The geochemical and optical maturity indicators represent late-mature oil to gas generation windows, implying that the Al Renk shale has substantial thermogenic gas generation potential. Therefore, high thermal maturation is a crucial factor in drastically altering the original organic matter (OM) and decreasing HI values (conversion of kerogen to hydrocarbons). The kerogen to oil conversion and the subsequent cracking of the retained oil into thermogenic gas have been simulated by the burial/thermal/generation models in the Agordeed-1 well. These models show that nearly 10–50% of kerogen was transformed into oil during the Late Cretaceous (78–68 Ma), correlating with the early to peak mature of oil generation window (0.62–0.85 %Ro). Moreover, oil was expelled from the Al Renk source rock system during the Late Cretaceous to Late Eocene. From the Late Eocene until the present, significant amounts of residual oil were cracked into gas due to the maturation of the gas generation window (>1.30 Easy % Ro), which is ideal for wet gas generation. Consequently, the findings of this study advocate for conventional gas exploration in the Melut Basin's deeper stratigraphic succession, where the Al Renk Shale Formation has reached a high maturity level of the gas generation window.

The effect of Pliocene volcanic intrusive rocks and thermogenic gas generation from the Miocene Salif Formation in the offshore Tihamah Basin, Yemeni Red Sea

Organic geochemical and basin modeling methods were used to investigate the potential of thermogenic gas generation from the source rock of the Miocene Salif Formation. The analyzed Salif shales were collected close to the intrusive volcanic rocks intersected by the Kathib-01 well in the offshore Tihamah Basin, Yemeni Red Sea. Generally, the analyzed Salif shale samples have total organic matter (TOC) values up to 3.4 wt %, overall, indicating organic matter richness capable of generating hydrocarbons. The analyzed Salif shale samples have low hydrogen index (HI) values of <200 mg HC/g TOC, indicating mainly Types IV and III kerogen. These results are in contrast with the presence of dominated hydrogen-rich Type-II kerogen in the Salif shales from the close location of the exploration wells e.g., Al-Auch-01, Al-Meethag −01 and Al-Meethag −02. Therefore, the drastic alteration of the original organic matter of Type II and decreasing HI values, as a result of conversion of kerogen to HCs in the studied well, is due to the high thermal maturation as indicated from thermal maturity indicators. The Salif shale samples in the studied well have reached the main stage of the gas generation window, implying that the Salif Formation has substantial thermogenic gas generation. The increase in thermal maturity in the studied well was caused by the presence of the intrusive volcanic rocks that extruded during the Pliocene age as a result of the regional uplift of rift shoulders.Based on the burial/thermal/generation model of the Kathib-01well, the conversion of kerogen to oil and the subsequent cracking of the retained oil into thermogenic gas has been simulated. During the early to late Pliocene age (5–2 Ma), 10 to about 60% of kerogen was converted to oil, matching the peak mature to late mature of oil window (0.75–1.35 %Ro). Moreover, oil was cracked into thermogenic gas during end of the late Pliocene until the present day (2-0 Ma), indicating the beginning of the gas generation window (>1.35% Ro) with a transformation ratio (TR) above 99%. The prediction of a significant charge of thermogenic gas generation from the Salif Formation in the studied Kathib-01 well is due to the presence of the volcanic intrusive rocks extruded during the late Pliocene to present day time.

Alterations of Carbonate Mineral Matrix and Kerogen Micro-Structure in Domanik Organic-Rich Shale during Anhydrous Pyrolysis

The study of organic-rich carbonate-containing shales after heating is an important task for the effective application of in-situ thermal kerogen conversion technologies implemented for these types of rocks. This research was conducted to study changes in the rocks of the Domanik Formation after high-temperature treatment, taking into account the nature of structural changes at the micro level and chemical transformations in minerals. The sample of organic-rich carbonate-containing shales of the Domanik Formation was treated in stages in a pyrolizer in an inert atmosphere in the temperature range of 350–800 °C for 30 min at each temperature. By means of X-ray powder diffractometry (XRPD), HAWK pyrolysis, light and scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy (EDX), and computed micro-tomography, the characteristics of the rock before and after each heating stage were studied. The results showed significant alteration of the mineral matrix in the temperature range 600–800 °C, including the decomposition of minerals with the formation of new components, and structural alterations such as fracturing micropore formation. The organic matter (OM) was compacted at T = 350–400 °C and fractured. The evolution of void space includes fracture formation at the edges between rock components, both in organic matter and in minerals, as well as nanopore formation inside the carbonate mineral matrix. The results obtained show what processes at the microlevel can occur in carbonate-containing organic-rich shales under high-temperature treatment, and how these processes affect changes in the microstructure and pore space in the sample. These results are essential for modeling and the effective application of thermal EOR in organic-rich shales.

Modeling the transformation of І and ІІІ types kerogen by the method of entropy maximization

Purpose, methods and research methodology. The aim of the work is to calculate and compare the trends of transformation of organic matter of I-A and III-A type kerogen, which is in contact with organic and inorganic gases in the process of immersion of organ-containing rocks. The calculations were performed for I and III type kerogen and a mixture of organic and inorganic gases within depths of 1-20 km and heat flows from 40 to 100 mW / m2. Results, scientific novelty and practical significance of research. A comparison and analysis of changes in the total entropy of the system was performed for I and III type kerogen, which showed the complex nature of the total entropy functional dependence on depth. It was revealed that the entropy has two reversible sections, the maxima of which are at a depth of 6 and 12 km. The analysis of changes in the Gibbs energy during the immersion of the geochemical system unambiguously indicates the presence of a stability zone for the hydrocarbon component. The maximum of this zone corresponds to the minimum value of the Gibbs energy, depends on the kerogen type and heat flow, is in the range of 4-7 km and indicates the area of stability, or "oil window". The complex nature of the balance between constitutional water and kerogen, depending on the heat flow and depth, has been established. To analyze this equilibrium, a simple dehydration equilibrium constant (Kd) was proposed, which generalizes the transformations of water in the kerogen matrix. Thermodynamic methods were used to calculate and compare the gas-generating capacity of I and III type kerogen for all heat flows, which showed that I type kerogen is the most productive with gas-generating potential, and III type is the least productive. To estimate the proportional composition of hydrocarbon gases in equilibrium with kerogen, the fat content coefficient of the gas generated by I and III type kerogen was calculated. It is shown that with immersion, the fat content coefficient first increases rapidly, which indicates an increase in the proportional content of alkanes heavier than methane. This growth reaches a maximum within 2-3 km for all considered heat flows, after which the fat content coefficient decreases. The equilibrium constant of the Kolbe-Schmitt reaction is calculated, which showed that regardless of the heat flow, the rate of kerosene decarboxylation decreases with increasing depth due to the shift of equilibrium to the left, and the contribution of this reaction to kerogen conversion is insignificant.

Verification of an Explicitly Coupled Thermal-Phase Field-Mechanical Electromagnetic (TPME) Framework by the Method of Manufactured Solutions

An explicitly coupled two-dimensional (2D) multiphysics finite element method (FEM) framework comprised of thermal, phase field, mechanical and electromagnetic (TPME) equations was developed to simulate the conversion of solid kerogen in oil shale to liquid oil through in-situ pyrolysis by radio frequency heating. Radio frequency heating as a method of in-situ pyrolysis represents a tenable enhanced oil recovery method, whereby an applied electrical potential difference across a target oil shale formation is converted to thermal energy, heating the oil shale and causing it to liquify to become liquid oil. A number of in-situ pyrolysis methods are reviewed but the focus of this work is on the verification of the TPME numerical framework to model radio frequency heating as a potential dielectric heating process for enhanced oil recovery. Very few studies exist which describe production from oil shale; furthermore, there are none that specifically address the verification of numerical models describing radio frequency heating. As a result, the Method of Manufactured Solutions (MMS) was used as an analytical verification method of the developed numerical code. Results show that the multiphysics finite element framework was adequately modeled enabling the simulation of kerogen conversion to oil as a part of the analysis of a TPME numerical model.

Application of Digital Volume Correlation to X-ray Computed Tomography Images of Shale

We investigated the Young’s modulus and Poisson’s ratio of Green River oil shale at elevated temperatures under triaxial conditions using an X-ray computed tomography (CT) scanner for in situ imaging, fast iterative digital volume correlation (FIDVC) for visualization of displacement and volumetric strain patterns, and a conventional linear variable differential transducer (LVDT) to measure the displacement independently. FIDVC was applied to time-lapse CT images to visualize the distribution of axial normalized displacement (Uz) and volumetric strain (εV) within the samples at the resolution of the CT images. Importantly, the displacement obtained by FIDVC was calibrated and verified with LVDT measurements. Both axial normalized displacement (Uz) and volumetric strain (εV) profiles from the FIDVC method present the location of greater strains within samples including layered material of greater density and lesser density organic matter (kerogen and bitumen) rich zones. The Young’s modulus remained unchanged upon heating to around 200 °C, but decreased following kerogen maturation at 350 °C. Young’s modulus decreased at 350 °C due to rock softening and conversion (maturation) of kerogen to oil or gas. Accordingly, the fraction of kerogen in a sample plays a critical role on Young’s modulus. These observations agree with trends found in the literature (White et al., 2017; Burnham, 2018), but without in situ imaging. Similarly, Poisson’s ratio did not change after pyrolysis but increased post maturation.

Natural fracture, cleat, and strong adsorption impact on low oil and condensate retention in the Carboniferous shales and coals of the western Black Sea Basin of Turkey

Total organic carbon (TOC) values of the Carboniferous shales and coals of the western Black Sea Basin of Turkey range from 0.72 to 71.52 wt. %, with an average of 32.3 wt. %, and generation potential chance from 0.33 to 184.64, with an average of 82.47 mg HC/g rock. Hydrogen index (HI) values of the shales and coals range from 24 to 384 mg HC/g TOC. The HI versus pyrolysis temperature at the maximum rate of kerogen conversion plot indicates that the organic matter is type II–III. The calculated vitrinite reflectance equivalent values of the shales and coals range from 0.63% to 1.32%. Thus, the shales and coals of the Carboniferous formations are represented by immature, effective oil and condensate generation windows. The shales and coals of the Alacaagzi Formation contain high quartz and lower clay. Oil saturation index (OSI) values of the shales and coals have been calculated as being 0.7 and 12 mg HC/g TOC, indicating possible lack of producible oil and condensate. The OSI values are lower than those of other coal-bearing and marine shales of the world. First, strong adsorption capacity may be a cause of the lower oil and condensate retention. Second, faults, natural fractures, and cleats related fluid flows may be important factors in these lower OSI ratios. The extensional, collisional, and inverse tectonic stages and diagenetic processes of coalification formed multiple interconnected faults, natural opening-mode fractures, and cleats in the shales and coals. Thus, 15 coalbed methane exploration wells failed to produce any economical coalbed methane.

Organic geochemistry and basin modeling of Late Cretaceous Harshiyat Formation in the onshore and offshore basins in Yemen: Implications for effective source rock potential and hydrocarbon generation

The purpose of this study is to present the source rock characteristics of Late Cretaceous Harshiyat Formation source rock in the onshore and offshore basins of Yemen (i.e. Mukalla-Sayhut, Sayun–Masilah , and Jiza-Qamar). Source rock geochemical characterizations were completed and integrated to perform 1-D basin modeling to back-predict source rock thermal maturation, oil generation and expulsion.The geochemical findings revealed that mudstone intervals within the Harshiyat Formation comprised favorable source rocks, with total organic carbon (TOC) content between 0.50 and 35.10 wt %. The organic matter intervals in the Harshiyat mudstones are mainly Types II/III and III kerogens, with certain amount of Type II and I kerogens based on Rock-Eval HI values, ranging from 40 to 923 mg HC/g TOC. Mixed kerogen types were consistent with vitrinite and sapropelic organic matters, as observed by visual kerogen examination and the distribution of biomarker fingerprints. The existence of mixed types I, II, and III organic matter suggests that the Harshiyat mudstones could contribute to oil and gas at sufficient thermal maturity levels. The biomarker data of the organic matter in the Harshiyat mudstones show that the source rock contains a mix marine phytoplanktonic-bacteria/terrestrial land plant enthronement and were deposited in suboxic-anoxic conditions.Results of chemical and optical maturity indicators led to the conclusion of varying maturity stages from immature to late oil window levels for the mudstones of the Harshiyat Formation. Thermal maturation distributions inferred from the analyzed samples indicate that mudstone intervals in the offshore Mukalla-Sayhut Basin are extremely mature, compatible with the late-mature oil window and may have generated significant amounts of oil. This interpretation was supported by strong geochemical similarity between the organic matter in the mudstones and those of the oils found in the offshore Mukalla-Sayhut Basin and demonstrated by the concentrations of n-alkanes and isoprenoids as well as carbon isotopes.In the offshore Ras-Ghashwah-1X well, burial and thermal models were constructed and used to address the effect of tectonic events in triggering oil generation and expulsion from mature Harshiyat source rock in the offshore area. Kinetic database models for Type II and III kerogen mixtures indicate that the initial conversion of kerogen to oil occurred since the Late Oligocene with transformation ratios (TR) that span between 10% and 50%. Furthermore, the oil was expelled from organic matter intervals in the Harshiyat source rock starting from Late Oligocene and continuing until Late Miocene, with TRs of 50%–72%. From that period up to the present, the retained oil was cracked into wet gas in the gas window with an Easy %Ro greater than 1.30, and with peak TR ratios greater than 72%.

Geochemical Evaluation of the Hydrocarbon Potential of Shale Oil and Its Correlation with Different Minerals–a Case Study of the TYP Shale in the Songliao Basin, China

Based on routine Rock-Eval experiments conducted on the source rock and dichloromethane-extracted portions of the same samples, total oil yield was calculated and compared with those obtained from the classic calculation equations. For shale in the early maturity and oil window, there is a large quantity of heavy constituents in the adsorbed state due to the carry-over and confinement effect, which leads to a lower calculated total oil yield. Therefore, S1e should be counted in the total oil yield when calculating the total oil yield. The original TOC was restored through a series of calculations. The ratio of the original TOC to the present-day TOC is between 1 and 1.79, with an average of 1.28. Therefore, it is not necessary to restore the original TOC through a series of complex calculations for shale source rocks with low to medium maturities and high residual TOC. Total oil yield is correlated with the siliceous and clay mineral to some extent, but it is poorly correlated with the carbonate mineral. Some special forms of organic sulfur may help enhance kerogen conversion to oil, which facilitates the shale to produce more oil during the early hydrocarbon generation stage.

Impact of marine incursions on lacustrine source rocks: organic matter quantity, quality, and kinetics in the Paleocene South Yellow Sea Basin, offshore eastern China

The impact of marine incursions during transgression, on the quantity and quality of organic matter in lacustrine source rocks, is critical to understanding their source rock properties and therefore on their hydrocarbon generation potential, but is also challenging and controversial. Here we examine this issue based on a case study in the South Yellow Sea Basin (SYSB) offshore eastern China, addressing organic matter (OM) quantity, quality and petroleum generation kinetics. A total of 139 lacustrine source rock samples was collected from the fourth member of the Paleocene Funing Formation (E1f4) in the SYSB, and investigated for organic petrographic and geochemical characteristics. The samples are immature to early oil window mature and the OM in all samples is dominated by terrigenous material, as shown by the organic petrography, relatively low hydrogen indices and biomarker distributions. The sediments are classified as inert to gas-prone. However, the presence of marine fossils (red and brown algae, coccolithophores and probably Neomonoceratinabullata) and the biomarker results, suggest that marine incursions occurred during the deposition of the lower unit of the E1f4 (E1f4L). The samples from this unit display higher HI values and more depleted δ13Corg ratios, but lower TOC and S1 + S2 contents, than the upper unit of the E1f4 (E1f4U) source rocks without marine influence. This suggests that marine incursions primarily improved the quality, rather than quantity, of organic matter. Bulk kinetics indicated that marine incursions also led to a more homogenous OM and compositional kinetics and phase properties suggest that black oil is generated throughout the process of kerogen conversion. Thus, our data suggest that marine incursions had a positive effect on the OM quality and oil generation potential of these lacustrine source rocks. Therefore, the impact of marine incursions should be fully considered during source rock evaluation of coastal lacustrine basins, especially during high sea-level stages. In addition, the greatest hydrocarbon exploration potential is observed in the South 4th Sag of the Southern Depression and thus this study provides valuable data for shaping regional exploration strategy in the SYSB.

Evolution of petroleum generation and expulsion of the oil-source rock in the north-western Say’un-Masilah Basin as inferred from 1D basin models of a single well (Al-Qarn-01)

The Madbi Shale Formation is the main oil-source rock for conventional petroleum extraction in the east-central Say’un-Masilah Basin. This study explores the generation and expulsion potential of oil from the Madbi source rock system in a deep well location (Al-Qarn-01) in the north-western Say’un-Masilah Basin using geological and geochemical modelling. One-dimensional (1D) basin models were constructed to the estimate thermal regime in the basin and the evolution of oil cracking and expulsion from the organic-rich intervals in the Madbi Formation over the geological time. In the studied Al-Qarn-01 well, the organic-rich intervals in the Madbi Formation are thermally mature, ranging from peak- to late-mature oil window stages; thus, half or more of the kerogen was converted to oil at these maturity stages. The basin modelling results of the studied well (Al-Qarn-01) show that oil was generated and expelled from Madbi source rock intervals in two main phases according to the conversion ratio (TR %) of kerogen. The main conversion of kerogen to oil (TR = 10–50%) occurred between Late Cretaceous and Early Oligocene (80–33 Ma) periods, corresponding to the peak-oil window (0.70–1.00 Easy %Ro). Furthermore, significant amounts of oil were expelled from the source rock, which subsequently migrated into the overlying reservoir rocks in the Early Oligocene time during the initial Tertiary rifting. The late-mature oil window (1.00–1.10 Easy %Ro) commenced during this time, with TRs of 50–77%.

Geochemistry and oil-gas generation modeling of the Late Cretaceous shales from the Chad (Bornu) Basin, Northeast Nigeria

Late Cretaceous Fika Formation shale was collected and analyzed from six wells in northeastern Nigeria's Chad (Bornu) Basin. The characteristics and the oil and gas-generating potential of the source are discussed based on combined geochemistry investigations and basin models. The abundance of marine phytoplanktonic-bacteria and land-plant suggested by biological markers indicate that the kerogen in the Fika shale Formation is a mixture of Types II and III, which is not compatible with the current low Rock-Eval HI findings of less than 200 mg HC/g TOC. The chemical and optical maturity parameters suggest that the Fika shales throughout the studied wells are in the early maturity stage of the oil window near the gas window point. Therefore, thermal maturation is the critical factor that significantly reduces the original HI values and modifies Types II and III to produce oil and gas.Based on the kinetic database models for Types II and III kerogen mixtures, the initial conversion of kerogen to oil has been occurring since the Late Cretaceous in the Kanadi-1 and Tuma-1 wells and since the Eocene in the Kinasar-1, Kuchalli-1, and Faltu-1 wells with transformation ratios (TR) between 10–31% and 10–50%, respectively. Furthermore, the oil was expelled from the Fika shale source rock in the Kanadi-1 and Tuma-1 wells at the end of Late Cretaceous, with TRs of 65–70%. From that period up to the present, the retained oil was cracked into wet gas in the gas window of 1.10–1.30 Easy %Ro with peak TR ratios greater than 65%.The distributions of thermal maturation, conversion ratio, and thickness suggest that the Fika source rock could generate substantial amounts of oil and gas in the southwest part of the basin. Therefore, the southwest part of the Chad (Bornu) Basin is considered a frontier exploration target.

Thermogenic gas generation from organic-rich shales in the southeastern Say'un-Masila Basin, Yemen as demonstrated by geochemistry, organic petrology, and basin modeling

The current study aimed to explore the gas-generating potential and oil-to-gas conversion in the Madbi oil-source rock system based on data from deep well within the Say'un-Masila Basin using both geochemical and petrological methods as well as basin models. Biomarker results for the bitumen from analyzed shale samples indicate mixed organic matter, with mainly phytoplankton, bacteria, and some terrigenous land plants, deposited under relatively anoxic marine environmental conditions. The terrigenous organic matter, and rich in lipids from phytoplankton and bacteria, suggests Types II and II/III as the original organic matter during deposition. Such findings are not consistent with the significant amounts of vitrinite and inertinite that found under microscope and the low current hydrogen index (HI) values of 43–282 (Types III/IV and III/II kerogen) of the analyzed shale samples. The chemical and optical maturity indicators show that the Madbi shales throughout the studied well section are at different thermal maturity stages, consistent with late-mature stage of the oil window to gas-generation window. Therefore, this high thermal maturation is the critical factor that significantly modifies the original organic matter.Based on the basin models of the single well studied (Ghayl Bin Yumain-01), the initial conversion of kerogen to oil, occurring between the Late Cretaceous and Late Eocene (75–38 Ma), corresponding to peak-oil window (0.70–1.00 Easy %Ro). Furthermore, the oil was expelled during the Late Eocene to Early Oligocene; hence, the late-mature stage of the oil window (1.00–1.30 Easy %Ro) commenced during this time, with transformation ratios (TR) of 50–70%. Subsequently, the cracking of the retained oil into gas has occurred from the Early Oligocene through the present and is attributed to the high thermal maturation of the gas window (>1.30 Easy %Ro), with maximum TRs of 70–97%.

A composite microstructural and geochemical approach to quench the quest for hydrocarbon from Barren Measures shales of Jharia Basin, India

The present study portraits the organic petrological, geochemical and microstructural characters of twenty borehole shale samples for assessing the hydrocarbon generation proficiency of the shales from the Barren Measures Formation (a stratigraphic unit of the Gondwana that is devoid of any workable coal seam) of the Jharia Basin, India, which was underinvestigated until now. The samples consist of vitrinite grains ranging from 5.41 to 20.57 vol%, the dominance of which compared to the inertinite and liptinites may reflect the lignocellulosic organic matter (type-III kerogen) input from the terrestrial plants. The range of the mean random vitrinite reflectance values (0.93–1.27%) may suggest the gas generation potential of the shale samples. The peak palaeotemperature values, may, in addition, suggest wet gas generation from these shales in complementary to some shale samples having efficiency to generate dry gas. The total organic carbon in these samples ranging between 3.87 and 15.99 wt% may imply good to excellent hydrocarbon generation capability. Rock Eval pyrolysis suggests the input of type-III kerogen within the mire and the correlations of the pyrolysis parameters exhibit that the shale samples possess significant potential to generate gaseous hydrocarbons (shale gas). The factor of kerogen conversion (f) of many shales suggests almost 20–30% transformation of kerogen to hydrocarbons. On attaining sufficient thermal maturity, the remaining large amount of labile chemical moieties may convert to hydrocarbons. The positive relation of the present-day hydrogen index (HIpd) with the A-factor would suggest the depletion of hydrogen containing functional groups for generating the gaseous hydrocarbons (shale gas). The Raman spectra of the samples reveal poorly organized microstructure, possibly, due to the presence of labile aliphatic compounds that would yet to generate hydrocarbons on attaining relevant thermal maturity as well as because of partially condensed aromatic system containing heteroatoms. The correlations of the Raman data with the mean random vitrinite reflectance data reveal generation of wet and dry gas from these shale samples based on the maturity level. The scientific content of this present study lies in suggesting a set of new equations from the relations obtained between of the Raman spectral parameters and the Rock Eval data in order to suggest the applicability of the Raman spectroscopy in elucidating the shale gas potential. These may be considered as the addendum to the applications of the existing techniques to elucidate the hydrocarbon potential of the organic-rich source rocks, which also add the novelty of this investigation. The new equations and the relations may be tested in the samples of different thermal maturity from other basins for substantiating their world-wide applications.

Scaling analysis of coupled compaction, kerogen conversion, and petroleum expulsion during geological maturation

Porosity is an important property of source rocks with implications on petroleum storage and expulsion. The evolution of porosity over geologic time-scales is controlled by coupled processes such as compaction, geothermal heating, kerogen kinetics, and fluid flow. Basin-scale models used to predict the evolution of porosity contain a large number of interdependent parameters. This poses a significant challenge on numerically solving the complex system of equations in field-scale simulators as well as quantifying the uncertainty induced by each parameter. Our objective is to identify the dominant mechanisms that control porosity evolution using scaling analysis. We develop a single-cell model that, despite simplifications, captures all important processes driving the physics, e.g., thermal, mechanical, chemical, sorption, and multi-phase flow. We then identify a minimum set of dimensionless numbers, each associated with a term in the governing equations, that have first-order impact on porosity evolution during primary and secondary cracking of kerogen. The insights here can be used to reduce the dimensionality of basin-scale models and to quantify uncertainty.