Thermal Maturity Research Articles

Laboratory investigation of permeability, pore space and unconfined compressive strength of uplifted Jurassic mudstones: The role of burial depth and thermal maturation

Laboratory investigation of permeability, pore space and unconfined compressive strength of uplifted Jurassic mudstones: The role of burial depth and thermal maturation

Paleoenvironmental, paleoclimatic, and organic matter assessment of the hybrid Kharita Formation (Albian) in the Abu Gharadig Basin, Egypt: Integration between palynology, organic petrography, and organic geochemistry

The Early Cretaceous (Albian) was a time of equatorial to polar temperature warming and increased environmental perturbations of the global carbon cycle and oceanic anoxia, which resulted in the widespread accumulation of organic carbon-rich sediments. During the Albian, the southern margin of the Tethys Ocean was characterized by marginal to shallow water conditions with minor phases of enhanced stratification and bottom water anoxia in northern Egypt. At this time, accumulation of the thick siliciclastic succession of sandstones versus shale intercalations of the Kharita Formation took place in the Abu Gharadig Basin. The Kharita Formation is investigated for palynological composition and palynofacies analysis, organic matter characterization, hydrocarbon generation potential, and thermal maturity assessment based on 30 and 26 drill cuttings samples from the BED2-3 and BED2-1x wells, respectively. A rich palynological assemblage of herbaceous hygrophilous plants, including pteridophyte spores and water ferns, along with Elaterates and Afropollis pollen indicated warm humid climate conditions. Furthermore, abundant occurrences of Araucariaceae and Cheirolepidiaceae, including Araucariacites, Inaperturopollenites, and Classopollis, reinforcing warm climatic conditions and their climax in areas near coastal vegetation. Statistical cluster analysis identified two palynofacies assemblages (PFA) based on stratigraphic variation in the particulate organic matter (POM). The PFA-1 characterized all samples of the BED2-3 and some intervals of the BED2-1x wells and comprised moderate abundances of phytoclasts and amorphous organic matter (AOM) that defined a kerogen Type II, whereas the PFA-2 was recorded only in the BED2-1x well and is dominated by phytoclast fragments of kerogen Type III. The geochemical screening revealed, based on the low average values of TOC (1.2 wt%), S2 (1.8 mg HC/g rock), and HI (146 mg HC/g TOC), that the Kharita Formation is characterized by a kerogen Type III of gas-prone hydrocarbon but with low generation potential. Tmax and vitrinite reflectance measurements along with greenish-to golden-yellow liptinite macerals indicated that the thermal maturity of preserved organic matter is still in the immature to the early mature stage of the oil window. Inconsistency in kerogen types between PFA-1 and geochemical deductions was interpreted in terms of microscopic investigations of the recovered AOM. Morphologic characteristics observed that most AOM particles were of terrigenous origin due to the impact of biodegradation and transformation of phytoclast particles into AOM, confirming a kerogen Type III of gas-prone hydrocarbons instead of Type II that was elucidated by palynofacies ternary diagrams. The occurrence of coaly matter in the BED2-1x infers closer proximity to fluvio-deltaic sources during deposition of the lower part of the Kharita Formation than in the BED2-3.

The diagenetic continuum of steroid hydrocarbon transformation from early diagenesis into the oil window

Steroids and their derivatives are ubiquitous in the sedimentary rock record, where they are widely applied as biological or geochemical markers to determine organic facies as well as thermal maturation of bitumen and oils covering the diagenetic to catagenetic stages. The diagenetic continuum from early diagenesis into catagenesis of steroids has not been extensively studied despite the importance of these reactions in influencing the successive continuum of late diagenetic transformations.This study utilizes a stratigraphically constrained transect of 9 wells from the Upper Cretaceous Second White Specks and Belle Fourche formations of south-central Alberta, Canada ranging in thermal maturity from 0.2 %VRE to 0.8 %VRE. Biomarkers were examined from 69 samples from 8 wells and thermal maturity was determined from 87 samples from 9 wells using HAWK programmed pyrolysis analysis. Relative and absolute abundances of regular sterane, diasterene, diasterane, monoaromatic steroid, and triaromatic steroid biomarkers and changes in the proportions of steroid compound classes were determined and evaluated for thermal maturity. Additionally, isomerization ratios within each of the compound classes were examined with increasing thermal maturation.Rearranged diasterenes initially dominate the steroidal hydrocarbons, followed by diasteranes in the late diagenetic and catagenetic stages and at peak oil maturity (0.8 %VRE) diasteranes were most abundant. The relative abundance of a steroid is initially controlled by its rate of production or isomerization from a biological precursor, but at higher thermal maturities selective catagenetic destruction alters the relative abundance of steroid classes, with aromatic steroids and regular steranes being degraded or expelled earliest. Thermal maturity parameters based on the isomerization of regular steranes, and the aromatization of monoaromatic steroids are effective thermal maturity indicators in specific but overlapping ranges beginning at 0.2 %VRE. This work represents a novel examination of a natural thermal maturity transect and helps to consolidate our understanding and application of the diagenetic transformations of steroid compounds.

Restoration of palaeogeomorphology and its petroleum-geological significance: Transitional-facies deposition during the early Permian in the southeastern Ordos Basin, North China

The identification of favourable shale-gas areas in marine-continental transitional shales are challenging because of the multiple thin producing layers and abrupt lateral pinch-outs. Using data obtained from drilling, logging, and 3D seismic and natural gamma spectroscopic logging, this paper investigates the control of early Permian palaeogeomorphology on the distribution of organic-rich shale in the southeastern Ordos Basin. Using the impression method and de-compaction correction of strata thickness based on seismic velocity reconstruction, we restore the karst palaeogeomorphology at the top of the Taiyuan Formation for the early Permian. Three geomorphic units including karst highland, karst slope, and karst depression are identified, and constitute a geomorphological pattern of interjacent depressions and highlands. In addition, based on the multi-lithological eigenvalue method, the spatial distribution of transitional shales in the Shan 2 lower sub-member of the lower Permian Shanxi Formation was inferred using post-stack seismic parameter inversion. Our results show that organic-rich shale is distributed mainly in the low section of Shan 2 lower sub-member, which is controlled by karst palaeogeomorphology mainly distributed in karst depressions. Organic-rich shale distributed in karst depressions are characterised by large cumulative thickness, high TOC, moderate thermal maturity, strong hydrocarbon generation intensity, and relatively high gas content, indicating that shale-gas sweet spots should be distributed mainly in karst depressions rather than in highlands or slope areas. Meanwhile, Th/U and Th/K ratios, which indicate paleo-environment during the period of shale deposition, show that the strength of reducing conditions was greatest in karst depressions, moderate in karst slopes, and lowest in karst highlands. Therefore, it is inferred that the distribution of shale-gas sweet spots may be related to the weakly reducing environment, which favoured the preservation of organic-rich sediments during sedimentation. The upper section of Shan 2 lower sub-member was dominated by a high-energy transitional sedimentary environment, and the paleo-redox conditions tended to be oxic, disfavouring the preservation of shale organic matter, and the organic-rich shale in the upper section is relatively poorly developed. This study shows that palaeogeomorphology and paleo-redox conditions affect the deposition and preservation of organic-rich sediments in lower section, the relationship between palaeogeomorphology and the distribution of organic-rich shale can provide reference for shale gas sweet spots prediction and promote the rapid exploitation of shale gas in eastern Ordos Basin.

Origins of Organic Matter, Paleoenvironment, and Hydrocarbon Potential of the Carboniferous Source Rocks from Shibei Sag, Junggar Basin, NW China

The organic-rich sediments of the Carboniferous in the Shibei Sag, Junggar Basin, China are potential source rocks with good hydrocarbon generation conditions for oil and gas exploration. Thus, it is meaningful to analyze their geochemical characteristics, including the hydrocarbon generation potential, genetic types of kerogen, thermal maturity, the origin of organic matter (OM), and sedimentary environment. The results reveal that the Carboniferous source rocks have fair to excellent hydrocarbon generation potential. They are mainly gas-prone with type III-IIkerogens. Random vitrinite reflectance (Rr) of the studied samples ranges from 0.63 to 1.04%, suggesting a primarily mature stage, which is also supported by the maturity-related hopane and sterane ratios. Stable carbon isotopic compositions, organic petrological macerals, and biomarker characteristics all indicate a predominant higher plant input. Abundant bicyclic sesquiterpenoids and diterpenoid biomarkers in the studied samples suggest the conifer inputs. In particular, high amounts of phyllocladanes, retene, and kauranes suggest the contribution of gymnosperms, pre-gymnosperms, pteridophytes, or bryophytes in swamps. From the early Carboniferous to the late Carboniferous, the environment became more oxic, the water level dropped, and higher plants flourished. Based on the abovementioned results, the Carboniferous source rocks were likely to be deposited in a transitional environment under lacustrine-fluvial conditions. Specifically, source rocks from the Batamayineishan Formation were deposited in a peat environment during the interval of the volcano eruptions. Considering the quantity and maturity of OM and their large thickness, the Carboniferous sediments have a good petroleum exploration potential.

Research on type I kerogen molecular simulation and docking between kerogen and saturated hydrocarbon molecule during oil generation

The interaction between kerogen and hydrocarbons is of great importance in the study of petroleum migration and reservoirs. In this study, type I kerogen was collected from Xinjiang Province, China and laboratory thermal maturation was used to investigate changes in the chemical structure of kerogen during hydrocarbon generation. A series of 2D and 3D kerogen molecular models were established with an increase in maturity, and the Gibbs free energy was calculated for the interacting kerogen and the selected free hydrocarbons. Based on the changes in kerogen structure, we found that during condensation reactions, protonated and branched aromatic carbon is continuously transformed into bridgehead aromatic carbon. fH a’, fB a’, fS a’ and fO a’ were proposed to evaluate this phenomenon. In addition, molecular docking was successfully applied to petroleum geochemistry. The results of the molecular docking indicated that both molecular size and relative proportion of methyl groups could affect the binding energy between geological organic matters. Therefore, kerogen might adsorb higher masses of n-C15 to n-C20 and isomers with more methyl groups. This study introduces the method of molecular docking into the research of oil and gas geological and it provides a new way for the selective adsorption phenomenon of solid–liquid organic matter interaction. And this research has important implications for method on oil migration and geochemical molecular simulation techniques.

Source and thermal maturity assessment of the Paleozoic-Mesozoic organic matter in the Risha gas field, Jordan

Detailed geochemical analyses of the Lower Silurian-Cretaceous shales in the Risha Field were carried out to determine their source input (marine or terrigenous), paleoenvironment, maturity, and hydrocarbon generation potential for their contributions to the gas field. The Lower Silurian shales are believed to be effective source rocks for oil within the Paleozoic petroleum system in the Risha field. Furthermore, the Upper Cretaceous shales have high hydrocarbon potentials and are considered as a promising source for oil and gas. The Upper Ordovician, Lower Silurian and Upper Cretaceous shales in the study area were deposited in a marine anoxic environment, resulting in the accumulation of highly liptinitic organic matters derived from algae and bacteria (Type II kerogen). The maturity of the Lower Silurian source rocks increases from the oil window to the gas window. Ordovician shales have reached the over maturity stage. Current hydrogen index (HI) values for the Silurian organic matter are relatively low after significant hydrocarbon production and expulsion. Two oil types are found from the standard petroleum geochemical analyses of the studied shales: naphthenic oil from immature Cretaceous black shales and high maturity paraffinic oils from Lower Silurian and Ordovician layers. The thermal history model of the Lower Paleozoic source rocks reveals that the Lower Silurian shales reached the dry gas generation stage 280–250 million years ago during Early Triassic, suggesting the large volume of gas accumulated in the Risha field mainly from the Silurian source rocks.

The deposition of type II-S Jordan oil shale in the context of Late Cretaceous source rock formation in the Eastern Mediterranean realm. Insights from organic and inorganic geochemistry and petrography

This study provides a detailed geochemical and petrographic investigation of 22 Upper Cretaceous Jordan Oil Shale (JOS) samples obtained from various wells distributed across Jordan. The JOS is generally characterized by high amounts of organic matter with total organic carbon (TOC) contents of 10–29 wt%, high carbonate contents of 15–75 wt%, and variable biogenic SiO2 contents of 1–50 wt%. The organic matter is oil-prone, reflected by a clear predominance of liptinite macerals and Rock-Eval Hydrogen Index (HI) values of 608–1078 mg HC/g TOC. In terms of elemental composition, bulk and molecular organic geochemistry and petrology, the JOS is similar to other age-equivalent organic-rich rocks from the Eastern Mediterranean. Primary bioproductivity was probably controlled by a Late Cretaceous upwelling event that affected the whole region. Low Pr/Ph ratios <0.5 indicate that organic matter preservation was not only controlled by the formation of an upwelling-related oxygen minimum zone but also by further oxygen depletion in isolated sub-basins. This setting led to vulcanization of kerogen; proven by a positive correlation between calculated organic sulfur contents and the amount of thiophenes generated during Curie-point pyrolysis. Although the thermal maturity is low (Tmax values < 430°C), significant amounts of hydrocarbons (up to 30 kg HC per ton of rock) are present within these rocks. The present bitumen fraction shows high concentrations of asphaltenes (10–65%) and NSO compounds (30–85%) with higher contributions in samples with the lowest thermal maturities. The relative contributions of aliphatic and aromatic compounds are correspondingly low, but increase with higher thermal maturities. Kinetic parameters suggest that isothermal pyrolysis at 350°C might be already enough to artificially convert 80% of the reactive kerogen within about one day, making the JOS a potential target for oil shale retorting.

Reservoir lithofacies study of the Toolebuc Formation, Eromanga Basin, Australia as a potential unconventional target

Open file data and new laboratory data were integrated with different lithofacies from gamma-ray (GR) response and core to interpret reservoir properties that would lead to a hydrocarbon potential targeting model for the Toolebuc Formation (Fm). The Toolebuc Fm is divided into an upward deepening cycle (UDC) followed by an upward shallowing cycle (USC), in which silica-rich argillaceous mudstone (Facies 1), mixed argillaceous mudstone (Facies 2) and interbedded calcareous mudstone and shelly thin beds/horizons (Facies 3) occur. Facies 1 is enriched in clay and silica component with relatively low Total Organic Carbon (TOC). Facies 2 has a mixed mineralogical composition with high TOC. Facies 3 is enriched in carbonates (coccoliths and shelly debris). The TOC value is high and shows large variation. The organic matter (OM) in the Toolebuc Fm corresponds to Type II kerogen and exhibits variability in maturity indicators but has arguably entered the early oil window. The dominant pore types of the Toolebuc Fm are intraparticle mineral pores and interparticle mineral pores while OM pores are rare. Samples collected from the basin centre show evidence of hydrocarbon generation.Vertically, the three lithofacies show a cyclic stacking pattern that corresponds to deepening and shallowing in a marine environment. Facies 1 is the transitional interval between the Toolebuc Fm and its adjacent units, the Wallumbilla Fm below and the Allaru Fm above. Facies 2 dominates the upward deepening cycle while Facies 3 dominates the upward shallowing cycle. The stacking of lithofacies corresponds to an upward increase and a following decrease in GR response, TOC, Brittleness Index (BI), and an upward decrease and a following increase in clay content.Facies 3 in the Toolebuc Fm shows the greatest unconventional potential due to the coincidence of the high TOC and BI. Facies 2 shows moderate potential with the high TOC and moderate BI, while Facies 1 is less favourable with the lower TOC and low BI. The target zone is located at the basin centre due to the higher thermal maturity relative to the marginal areas.

Stress sensitivity of multiscale elastic properties under hydrostatic loading conditions of organic shales at different thermal maturity stages

Shales serve essential functions as seals for conventional hydrocarbon reservoirs, waste storage repositories and unconventional plays. Exploration and evaluation of shales rely on the characterization of their multiscale elastic properties. However, there are limited studies on the geologic controls of elastic stress sensitivity in organic shales. This study investigated dry Lokpanta, Bakken, and Niobrara shales of different thermal maturity stages. First, we used a pulse-transmission ultrasonic setup to conduct multidirectional (0o, 45o and 90o) hydrostatic-stress sensitivity (0–27.58 MPa) tests to measure elastic waves and derive other elastic properties. Furthermore, we inverted microscopic parameters from the elastic measurements based on effective medium theories such as damage parameters (αij and βijkl), crack density (ρ), normal to tangential microcrack compliance (B), specific tangential crack compliance (snBT) and microcracks orientation anisotropy (η). Finally, we studied the effects of organic matter maturity and clay diagenesis on the multi-scaled elastic stress sensitivity. Under applied hydrostatic stress, the non-linear elastic response in the shales is consistent with the closure of aligned microcracks. Microcrack closure decreased the elastic anisotropy at lower stress (<10 MPa), while aligned clays and organic matter control the stress-insensitive anisotropy at higher stress. As organic matter matures and smectite transforms to illite, orthogonal velocity stress sensitivity increases and extrinsic contribution to elastic anisotropy increases. There is also a corresponding increase in orthogonal damage second-rank tensor (α33) and a decrease in orthogonal damage fourth-rank tensor (β3333) with organic matter-clay thermal maturity. These relationships are due to the thermally-induced development of new and/or extensional roughly-textured microcracks parallel to the laminated microfabric, which is of higher compliance in the shear than compression. Microcrack closure also decreases ρ under applied pressure. Most of the samples had B < 0.5, suggesting the presence of non-idealized roughly textured microcracks. Generally, snBT broadly decreases and η increases with clay diagenesis and organic matter maturity also because of the generation and/or enhancement of aligned microcracks resulting in higher tangential stiffness.

Hydrogen Diffusion in Organic-Rich Porous Media: Implications for Hydrogen Geo-storage

Subsurface hydrogen storage for large-scale energy supply to decarbonize a variety of greenhouse gas-emitting activities is gaining momentum worldwide to combat climate change. Hydrogen’s extensive range of flammable concentrations and low minimum ignition energy in air combined with its highly diffusive nature mandate implementation of comprehensive risk management protocols to maintain storage safety. In particular, the role of hydrogen diffusion process (self-diffusion) needs further investigation to understand H2 transport behavior and elude the associated risk of leakage for the long-term safety of the underground hydrogen storage process. Recent molecular simulation studies suggest that, compared to other subsurface storage options, depleted shale reservoirs may offer preferential storage characteristics due to excellent sealing and adsorption capabilities of shale. Data on hydrogen diffusion in organic (kerogen)-rich shale is scarce. Here, we applied molecular dynamics to compute hydrogen self-diffusivity in kerogen systems with different structures at various pressures, ranging from 3 to 41 MPa, and under an isothermal condition of 360 K. Two kerogen types of varying maturity (II-A and II-C) were utilized to create slit nanopores of 0.5 and 2 nm in size. The Knudsen number was calculated based on the mean free path and determined by the density values obtained from simulation to improve diffusion coefficient estimates. Results obtained indicate the Kn data in the range from 0.64 to 9.72, demonstrating that the main transport mechanism was transitional in nature. With increasing pressure, diffusivity declined regardless of the slit pore size or kerogen type. H2 diffusion was greater for the 2 nm pore system compared to both the 0.5 nm in II-A (0.004–0.02 cm2/s) and II-C (0.0037 to 0.019 cm2/s). In addition, for a fixed nanopore size, thermal maturity does not seem to impact diffusivity. Finally, simulation results were regressed to delineate a continuous description for diffusivity as a function of pressure. For curve fitting, R2 values were found to be 98 and 92% for 2 nm pore size of II-A and II-C, respectively, while 97 and 79% for 0.5 nm pore size of II-A and II-C, respectively. The results obtained are not only of interest for storage of hydrogen in shale but also for any subsurface hydrogen storage approach where a shale layer acts as a seal to form a trap.

Uncommon Distribution of C20 and C21 Tricyclic Terpanes in Niger Delta Crude Oils

C20 and C21 tricyclic terpanes were investigated in crude oils from Niger Delta, Nigeria. From comparison of the mass chromatograms (m/z 191) of two crude oil samples (CEN-21 and WST-69) with related literatures on tricyclic terpanes which eluted from the gas chromatography (GC) within certain retention time, 12 peaks were selected. Peaks 1 - 5 were selected as C20 tricyclic terpane isomers (TR20a-e) and peaks 6 - 12 selected as C21 tricyclic terpanes (TR21a-g). This distribution is usually as crude oils show a single peak each and indicate the distribution of C20 and C21 tricyclic terpanes in the Niger Delta crude oils is uncommon. Total abundances showed the C20 and the C21 tricyclic terpanes were more in CEN-21 than WST-69 with ratios of 3.07 and 1.84, respectively, with TR20a, TR20b, TR20d and TR21d being the most abundant isomers in both oil samples. These abundances indicate CEN-21 was thermally more mature than WST-69 and that the C20 tricyclic terpanes were generated more than the C21 tricyclic terpanes with increasing thermal maturity of the crude oils. Significant similarities observed in the normalized composition profiles and 66 derived ratios suggest the Niger Delta crude oil samples were genetically related and were predominantly derived from terrigenous Tertiary deltaic petroleum systems. Some differences observed in the composition profile and derived ratios indicate minor input from a different source, depositional environment and/or maturity level and are suggestive as indicators for evaluation, correlation and/or discrimination of the Niger Delta crude oils.

Speciation of trace elements in the Bowland Shale

Abstract Samples of the Bowland Shale and equivalents in Ireland that represent a range of thermal maturities from the oil window to gas window contain trace elements distributed through multiple residences. The trace element distribution reflects the depositional environment, and influences subsequent element release. Measurements of Se, Cu, As, U and Mo indicate variable retention in loosely bound and strongly bound forms. The trace elements are especially associated with diagenetic pyrite. Shales from Ireland, at higher thermal maturity, have relatively high proportions of loosely bound Se, Cu and As, which may reflect expulsion from the pyrite during recrystallization. The shale samples consistently contain high organic matter contents, reflecting deposition in an anoxic environment. The Se, Mo and U in particular may be bound to organic matter, which may have adverse environmental impacts upon weathering of the shale.

Evaluation of the molybdenum isotope system as a petroleum tracer: The Phosphoria petroleum system, western U.S.A.

The molybdenum (Mo) isotope composition of organic-rich mudrocks is used to infer paleo-ocean redox conditions but the potential of this isotope system as a petroleum tracer is uncertain. In this study, we measured the Mo isotope compositions of crude oils, asphaltene separates, and organic-rich source mudrocks (Meade Peak Member and Retort Member of the Permian Phosphoria Formation) for the Phosphoria petroleum system, western U.S.A. Crude oils from the Bighorn Basin have Mo concentrations of 0.01–0.39 μg/g that are significantly lower than Mo concentrations of 10–443 μg/g for the organic-rich mudrocks (2.4–16.6 wt% total organic carbon; TOC), suggesting inefficient transfer of Mo from source rock kerogen to oils. Asphaltene Mo concentrations are elevated (1.0–3.2 μg/g), indicating that asphaltene is an important host of Mo in the Phosphoria crude oils. However, statistically insignificant correlation between crude oil and asphaltene Mo concentrations as well as differences between the δ98Mo of some crude oils and their asphaltene separates (Δ98Moasphaltene–crude oil between −0.5‰ and +0.1‰) suggests other important hosts for Mo in the non-asphaltene fraction of the Phosphoria oils. The overall range of δ98Mo for fifteen Phosphoria crude oils and six asphaltene separates is 0.5–1.7‰ and 0.8–1.5‰, respectively. Crude oils unaltered by reservoir processes (biodegradation, water washing, thermochemical sulfate reduction) have δ98Mo of 1.1–1.4‰ whereas crude oils mildly affected by biodegradation and/or water washing span a wider range of δ98Mo (1.0–1.7‰). Five crude oils altered by thermochemical sulfate reduction (TSR), as indicated by higher δ34S, have lower δ98Mo (0.5–0.9‰), suggesting that TSR decreases the δ98Mo of crude oils via redox reactions and/or the introduction of external fluids containing isotopically light Mo into the oil reservoir. Biodegradation may cause variable δ98Mo in crude oils via kinetic isotope effects, microbial processes, or the recapture of isotopically distinctive Mo released from biodegraded oils elsewhere. A statistically significant inverse correlation between δ98Mo and δ34S for non-TSR altered oils may reflect a decrease in the δ98Mo of crude oils with increasing thermal maturity, perhaps associated with de-metalation reactions and/or formation of new organo-metal compounds. The δ98Mo of the unaltered crude oils falls within the range of δ98Mo for the Mo- and TOC-rich source rocks of the Retort and Meade Peake Members (1.0–2.0‰), suggesting the Mo isotope system has potential as an oil – source rock tracer. This application will have the most success in petroleum systems whose source rock(s) exhibit a narrow range of distinctive δ98Mo. Our study shows the Mo isotope system has promise as a petroleum tracer and potentially could be useful for studies on petroleum contamination in the environment.

Biological Marker Fingerprints of Crude Oils from Three Oilfields in the Central Niger Delta: Implication to Source Input, Conditions of Deposition, and Thermal Maturation

Crude oil samples recovered from three oilfields distributed within the central Niger Delta were used to investigate biological marker fingerprints, sources of organic matter, conditions of deposition, and thermal maturation. This was achieved by the application of gas chromatography-mass spectrometric (GC-MS) analyses on the saturated components of the crude oils. The biological marker ratios show low sterane/hopane (steranes/hopane ˂ 1) in the scope of 0.29 to 0.61 indicating that the crude oils initiated from rocks containing high terrigenous biota (mainly land plants). The n-alkanes distribution and the pristane/phytane ratios (0.63 to 2.08) suggested source deposition under oxic to suboxic environmental conditions. The percentage composition of C27, C28, and C29 steranes and oleanane index (18α (H)-oleanane/ C30 17α (H)-hopane) also indicated major contributions from terrigenous organic biota with minor marine source input. The studied crude oils have C32:22S/ (22S+22R) ratios in the scope of 0.55 to 0.64, and these values suggested high maturation level. This agrees with the oleanane index (0.64 to 0.95), CPI (0.92 to 1.06), C29: 20S/ (20S + 20R) sterane ratios (0.29 to 0. 61), Ts/(Ts+Tm) ratio (0.45 to 0.83) and moretane/C30 hopane proportion (0.16 to 0.24). Keywords: Biological marker; Depositional conditions; Niger Delta; Organic matter; Thermal maturation.

PAHs in medium and high rank Bulgarian coals – insights from aromatic indices

The study presents analyses of aromatic components in bitumen extracts from Bulgarian medium and high rank coals. Bulk samples from Balkan, Ro = 0.96%, Dobroudzha, Ro = 1.13%, and Svoge, Ro = 5.20% coal-bearing provinces, were considered. After extensive chromatographic separation and GC-MS study of the aromatic fractions, our attention was focused on polycyclic aromatic hydrocarbons (PAHs) compositions. Aromatic indices, based on quantification of individual compounds, revealed that: (i) the highest amounts of PAHs were present in Balkan and Dobroudzha samples, 219–365 μg/g TOC, and dropped to 3.5 μg/g TOC at Svoge sample; (ii) the alkylated naphthalenes and phenantrenes prevalence confirmed published data; (iii) the relationship between aromatic indices vs. Ro, % is in agreement with the previously obtained results, indicating their decrease with thermal maturity. For some indices only weak correlation was obtained, suggesting that PAH concentrations are not solely affected by coal rank, but also by environmental conditions and vegetation.

Comprehensive Fluid Compositional Analysis Program to Support the Interpretation of Chichimene Field In-Situ Combustion Pilot

Summary The evaluation of enhanced oil recovery (EOR) methods in Colombia has been very active during the past decade. One of the most recent and promising pilots is the in-situ combustion (ISC) in Chichimene field, starting in September 2019. Based on international ISC field experiences, this pilot represents a unique case study given the depth (≈8,000 ft) of this heavy crude oil (9 °API) reservoir. The pilot project consists of one injector, seven producers, and two temperature observation wells between the injector and first-line wells. Production response shows encouraging results. Its interpretation is supported by a comprehensive fluid compositional analysis, which is the main objective of this paper. This paper describes the compositional analysis of produced fluids (gas, oil, and water) and the influence of the current flow assurance program. Geochemical simulations support the evaluation of scaling tendencies, and possible corrosion trends are based on iron and manganese concentrations following the National Association of Corrosion Engineers (NACE) standards. Crude oil analysis is based on conventional techniques (i.e., acid number, distillation curves, etc.) and biomarkers to infer possible thermal maturation changes in the produced oil. Results confirm predicted cycles of CO2 and H2S during the planning of the monitoring program. The solubility of both gases in water leads to their acidification and the formation of carbonate and sulfate scales characterized in production wells. The precipitation of solids was also influenced by the N2-based H2S scavenger decomposition downhole due to the water pH increment observed with the dosage increases. The scaling tendencies did not impact the productivity due to the high reservoir permeability. The precipitation of iron species made it difficult to interpret NACE standards to infer corrosion except for wells shut in for more than 2 months showing a higher concentration of Fe and Mn. However, a recent casing inspection job at one of the first-line producers shows no corrosion signs. Heavy metals such as nickel and vanadium were analyzed in water to infer the possible corrosion or thermal cracking of porphyrins in crude oil. Changes in the paraffinic fractions and biomarkers (i.e., methyl phenanthrene index, mono- and tri-aromatic steroids) suggest an increased thermal maturity of the produced oil. The robust monitoring program has provided important insights from the ISC process and flow assurance strategy supporting possible expansion plans. This study provides valuable guidelines for monitoring programs based on compositional analysis of produced fluids, including the influence of production chemistry. Lessons learned through the Chichimene ISC monitoring program can be valuable in interpreting thermal and potentially nonthermal EOR projects.

Occurrence state and oil content evaluation of Permian Fengcheng Formation in the Hashan area as constrained by NMR and multistage Rock-Eval

The Hashan area, neighboring the Mahu Sag that is rich in the shale oil resources, showed commercial oil flow in the corresponding lacustrine shales of the Lower Permian Fengcheng Formation (P1f) with reserve scale approximately 789 million tons, presenting great potential for oil exploration. Despite their geographical proximity, the hydrocarbon occurrence and oil-bearing capacity of shale in the Hashan area and Mahu Sag greatly differ owing to the complex tectonic evolution. Therefore, understanding the occurrence state and oil content of the P1f in the Hashan area is crucial for ongoing shale oil exploration activities and the development of the northwestern margin of the Junggar Basin. In this study, an integrated investigation, including petrological observations, scanning electron microscopy (SEM) observation, analysis of nuclear magnetic resonance (NMR) T1–T2 spectra, and conventional and multistage Rock-Eval pyrolysis methods were conducted to evaluate the occurrence state and oil content of the P1f shale in the Hashan area. The results indicate that plagioclase (average 30.7%) and quartz (24.1%) dominate the mineral compositions of the P1f shale samples. A method involving quartz–plagioclase–carbonate minerals is proposed to conduct lithofacies classification. In the Hashan area, the organic matter abundance in the P1f shale is scaled in fair to good range, the thermal maturity ranges from immature to early mature stage, and the primary organic matter types are Types I and II1. Intergranular and dissolution pores are the two most common pore types. The free oil is mostly found in the pores and microfractures of the mineral matrix, whereas the adsorbed oil is mostly adsorbed on the surfaces of kerogen and clay minerals. The high organic matter abundance, quartz content, and porosity account for substantial increase in the oil content, the area rich in shale oil resources coincides with that rich in free oil. The most favorable lithofacies in the Hashan area is the calcareous mudstone/shale, which hosts the highest free oil content (average 2.49 mg), total oil content (15.02 mg/g), organic matter abundance (TOC = 1.88% and S1+S2 = 20.54 mg/g) and porosity (5.97%).

Depositional Environment and Hydrocarbon Distribution in the Silurian–Devonian Black Shales of Western Peninsular Malaysia Using Spectroscopic Characterization

The present study aimed to evaluate the hydrocarbon functional groups, aromaticity degree, and depositional environment in the Silurian–Devonian Kroh black shales of western peninsular Malaysia. Fourier transform infrared spectroscopy (FTIR) was applied to measure the hydrocarbon functional groups in the sedimentary succession and associated organic matter of the black shale samples. The results showed that aromatic C=C stretching, aromatic C-H out-of-plane, aromatic C-H in-plane, and aliphatic =C–H bending are the major hydrocarbon functional groups in the Kroh shales. Also, ultraviolet-visible spectroscopy (UV-Vis) was used to evaluate the type of humic substance and analyze the sample extract ratios of E4/E6. It was revealed that the methanol-treated Kroh shale samples ranged from 0.00048 to 0.12 for E4 and 0.0040 to 0.99 for E6. The lower E4/E6 ratio (&gt;5) indicates the dominance of humic acid over fulvic acid in the Kroh shales. The Kroh shale samples’ total organic carbon content (TOC) ranges from 0.33 to 8.5 wt.%, analyzed by a multi-N/C 3100 TOC/TNb analyzer. The comparison study revealed that the TOC content of the Kroh shale has close obtainable values for the Montney shales of Canada. Furthermore, both hydrocarbon functional groups from FTIR, and the E4/E6 ratio from UV-Vis show no correlation with TOC content. It is revealed that humic acid, aromatic, and aliphatic hydrocarbons are not the controlling factors of the enrichment of organic matter in the Kroh shales. Conversely, a positive correlation between aliphatic and aromatic hydrocarbons in the Kroh shales indicated that organic matter is thermally overmatured. The presence of humic acid and enrichment of aromatic hydrocarbons in the Kroh shales demonstrated that the organic matter in these shales contains plant-derived hydrophilic minerals, i.e., terrestrial in origin. These findings may provide clues on the depositional and thermal maturation of organic matter for the exploration efforts into the pre-Tertiary sedimentary successions of the peninsular.

Microstructural Analysis of Organic-Rich Shales: Insights from an Electron Microscopic Study by Application of FIBSEM and TEM

Matrix-related pores play a significant role in controlling hydrocarbon production in organic-rich shales. Multiple matrix-related pore types of typical marine shales in the Sichuan Basin have been visually investigated and identified by transmission electron microscopy (TEM) on ultra-thin sections and by focused ion beam-scanning electron microscopy (FIBSEM) on polished sections. OM-hosted pores seem universal and range in sizes from below 1 nm to hundreds of nanometers and they are not homogeneously developed and distributed, which is mainly determined by thermal maturity and OM composition. Mineral-hosted pores are defined by mineral frameworks and occur in open spaces related to ductile or rigid grain fabric. The four porous mineral types that occur are clay intrapores, carbonate solvopores, pyrite interpores, and quartz interpores, and they range in size from less than 1 nm to more than several microns. Aggregate-hosted pores are predominantly associated with clay-organic aggregates, pyrite-organic aggregates, clay-pyrite aggregates, and clay-organic-pyrite aggregates. The most common aggregate-hosted pore networks are defined by clay-organic aggregates, and the pores are largely developed between the clay and organic layers and may be the important adsorption spaces for methane. Fracture-related pores include microchannels and microfractures of various sizes and shapes and they could play a key role in providing hydrocarbon migration pathways. FIBSEM and TEM show direct evidence that OM-hosted pores and fracture-related pores contribute more to the effective pore network and the excellent reservoir quality, whereas poor reservoir quality may come from aggregate-hosted pores.