Kerogen Research Articles

Origin of hydrocarbon and noble gases, carbon dioxide and molecular nitrogen in Devonian, Pennsylvanian and Miocene strata of the Polish Lublin and Ukrainian Lviv basins, southern part of the Upper Silesian Coal Basin and western part of the Carpathian Foredeep (Poland)

Sixteen natural gas samples were collected from Devonian, Pennsylvanian and Miocene strata of the Polish Lublin and Ukrainian Lviv basins, from the southern area of the Upper Silesian Coal Basin (USCB) and western part of the Carpathian Foredeep (CF) in Poland. The samples were analysed for the molecular composition and stable isotope compositions of gaseous hydrocarbons (CH4, C2H6 and C3H8) and CO2,N2, and noble gases (He, Ne, Ar, Kr, and Xe) in order to reveal the origin and migration pathways of these gases. Hydrocarbon gases and the majority of the of CO2 were generated during two stages of thermogenic processes from Type-II and II/III kerogens in the Lublin Basin, and during both thermogenic and microbial processes in the Lviv Basin. The thermogenic component was generated from Type-II kerogen. Coal-bed hydrocarbon gases accumulated in the Pennsylvanian strata of the southern part of the USCB, originated from both thermogenic and microbial processes. Isotopically light microbial methane may have migrated from Miocene (Upper Badenian) Skawina Formation of the CF to Carboniferous coal-bearing strata and/or might result from diffusion and adsorption-desorption processes during the migration of thermogenic gases from deeper lying coal seams through the microporous coal structure. Hydrocarbon gases and carbon dioxide which accumulated in the sandstone reservoirs of Upper Badenian Skawina Formation of the western part of the CF, most probably were generated from dispersed organic matter within the claystones and mudstones of these strata and at least partly migrated from the Carboniferous coal-bearing strata of the USCB. N2 could have been produced as a result of various biogenic and abiogenic processes, and contributed to the atmospheric component. Characteristic radiogenic 4He composition of the analysed gases suggest the accumulation of α-particles formed from U and Th radioactive decay in the crustal gas reservoirs. Radiogenic 40Ar and nucleogenic 21Ne with abundance ratios characteristic of crustal reservoirs were also observed. Addition of mantle-derived He to the gases from Miocene strata is evident from elevated 3He/4He ratios ranging between 0.2 and 1.6 × 10−6. A small contribution of Ne from the mantle along with He is also suggested by the slightly elevated 20Ne/22Ne ratios relative to atmosphere. The mantle component is most likely to have migrated from the upper mantle to the gas reservoirs through the deep-seated Bzie-Czechowice Fault Zone.

Sulfur isotopic composition of gas-phase organic sulfur compounds provides insights into the thermal maturation of organic-rich rocks

Volatile and gas phase organic sulfur compounds (VOSCs) are important components in subsurface reservoir fluids and despite their relatively low concentrations, can provide important information about organic matter origin, diagenetic transformation, thermal maturation, and oil and gas generation, expulsion, and migration. We present an approach for the utilization of VOSC concentration and compound specific S isotopes ratio (δ34S) data as a new geochemical tool to study natural gas origin and formation. We studied the formation pathways of VOSCs, their δ34S values, and interaction with an organic-rich sedimentary rock (or ‘source rock’) from the Ghareb Formation (Type II-S kerogen) deposited in an upwelling marine environment. The immature source rock was subjected to laboratory controlled thermal maturation. We used a semi-open, non-isothermal pyrolysis system heated between 200 and 440 °C, and analyzed the molecular composition and compound specific δ34S values of the evolved gases at various thermal maturity stages. Formation of VOSCs commenced at 206 °C, a temperature generally associated with less thermally mature systems, and typically before the onset of oil generation for similar organic-rich source rocks, allowing study of low thermal maturity conditions (∼0.3 %Roeq). Overall, the VOSCs obtained had δ34S values similar to the bulk kerogen values (mostly within 4‰). However, thiol (or mercaptan) δ34S values closely followed those of H2S (Δ34Sthiols-H2S = −1 ± 1‰) throughout the experiment. Ab-initio calculations for the S isotopic exchange between H2S and thiols were close to the experimental observations. This suggests that thiols rapidly attained equilibrium with H2S despite their very short residence time in the system (minutes to hours). Furthermore, throughout the experiment, the concentrations of the six different thiols were found to be proportional to the coexisting, concentration ratio of [H2]/[H2S]. The proportionality factors of the 6 different thiols strongly correlate with reported heats of formation (ΔHf°), further supporting the notion that the generation of thiols in the system rapidly reached equilibrium. At pyrolysis temperatures up to 350 °C, δ34S and concentration values of other VOSCs produced in the gas phase, including sulfides and thiophenes, probably represent generation from S-containing moieties in kerogen and bitumen with limited interaction with co-existing H2S. The reaction of hydrocarbons and H2S to produce VOSCs is inversely correlated with thermal stability, i.e. thiols > sulfides > thiophenes. Therefore, the δ34S values, concentrations and distributions of VOSCs can be utilized as a proxy for reaction extent and formation mechanism of petroleum and H2S, including primary generation by thermal maturation, or potentially other processes such as migration and thermochemical sulfate reduction. This work demonstrates a novel and useful geochemical tool to study the source and fate of natural gas in the subsurface.

Impact of Water Pressure on the Organic Matter Evolution from Hydrous Pyrolysis

Deep oil and gas, as an important part to make up the energy-deficient. A series of breakthroughs had been made in their exploration and development in the past few years. However, the effects of deep fluids during hydrocarbon formation and evolution are still an ambiguous problem. Therefore, to investigate the effect of water pressure (PW) on hydrocarbon generation and thermal evolution of type-I, type-II, and type-III kerogens in a deeper stratum, three series of pyrolysis experiments were conducted on three samples with different kerogen types (types II₁, I, and III in TC, YMS, and XJ samples, respectively) in a high-temperature, high-pressure simulator. The type-I kerogen was pyrolyzed with 5, 20, 35, 50, 65, and 80 MPa water pressure at 375 °C for 48 h, whereas the type-II and type-III kerogens were pyrolyzed with 10, 20, 30, 40, 50, and 60 MPa water pressure at 350 °C for 48 h. The results showed that there was a threshold pressure PW affecting liquid hydrocarbons. In addition, before the threshold pressure, PW played a role in promoting, but then it was the inhibiting. For gaseous hydrocarbons, while the pressure effects and results were the same as with liquid hydrocarbons in TC samples under the near-critical or critical state, they had no obvious effects in YMS and XJ samples before the critical state, which proved that the organic matter (OM) evolution was associated with the state of fluid in the reaction system and the effects were stronger when the fluid was under the near-critical or critical state than when it is not under this state. The reasons could be concluded as follows: (1) the different properties of water, as the ionization product constant of water (K(w)) was higher in TC samples and may provide more H⁺ to participate in the OM reactions compared to YMS and XJ samples. Moreover, the particular characteristics of intersolubility with organic solvent occurred under near-critical or critical states, resulting in the more water-soluble hydrocarbons being expelled in TC samples. (2) Chemical mechanism: based on the first-order reaction equation for oil–gas generation and essential characters of samples and experiments, it can be concluded that the influence degree of PW on OM evolution was related to the type of OM, the thermal maturity as well as the nature of water. (3) Physical mechanism: the vapor in free space and generated hydrocarbons in pores were in a dynamic balance state, which also resulted in the existence of threshold pressure PW affecting OM evolution. Therefore, understanding the effects of PW on OM evolution would help us to study the oil–gas generation accurately in actual geology and help preferably in oil–gas exploration and exploitation.

Characterization of free and bound bitumen fractions in a thermal maturation shale sequence. Part 1: Acidic and neutral compounds by negative-ion ESI FT-ICR MS

To evaluate petroleum generation and expulsion processes, pyrolysis experiments that simulate increased overburden pressures were conducted on an immature organic-rich shale with type-II kerogen. Expelled oils and residual rocks with different maturities covering the oil window were recovered from the experiments. The residual rocks were then subjected to stepwise extraction in conjunction with stepwise dissolution of the carbonate and silicate minerals to obtain free and bound bitumen fractions. The compositions of acidic and neutral compounds in both expelled oils and bitumen fractions were investigated by negative-ion electrospray (ESI) Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS). Neutral nitrogen compounds were found to only exist in expelled oil and free bitumen, while acidic compounds (typically contain carboxylic functional group(s)) were prevalent in bound bitumen. Oxygen-containing functional groups with high polarity in oxygen-containing compounds and oxygenated nitrogen/sulfur compounds are proposed to be the dominant bonding forces that facilitate the interaction between bitumen and mineral matrix or kerogen. Semiquantitative results of acidic compounds reveal that the distributions of acidic compounds in both free and bound bitumens vary throughout the oil window stage, especially for those in the bound phase after an intense oil expulsion from the shale at Easy%Ro > 0.9. During maturation, acidic compounds in free and bound bitumens gradually decreased in their abundances. However, oil expulsion from the shale brought about a significant redistribution of acidic compounds among expelled oil, free and bound bitumens. These results indicate that polar components in shales are closely related to thermal maturation of organic matter and oil expulsion from the shales in a petroleum system.

Comparative study on sorption characteristics of coal seams from Barakar and Raniganj formations of Damodar Valley Basin, India

The methane retention mechanism in coal seams is markedly different from those of conventional gas reservoirs. Methane remains mainly as physically adsorbed molecules on micropore surface. Chemical and petrographic compositions of coal are the measures of maturity and type of organic matter that control the methane sorption characteristics of the coal. 99% of Indian coal occurrences are contributed by lower Gondwana sequences housed in two major geologic formations, younger Raniganj and older Barakar. The Raniganj Formation is best exposed in Raniganj Sub-basin and Barakar Formation is best exposed in Jharia Sub-basin of Damodar Valley. Present work attempts a systematic investigation on comparative account of methane sorption characteristics of coals from Raniganj Formation of Raniganj Sub-basin and Barakar Formations of Jharia Sub-basin in relation to their chemical composition and petrographic makeup. Chemical analyses shows that moisture, ash, volatile matter and fixed carbon varies between 2.5 and 4.6%, 10.0–27.2%, 38.8–40.2% (dmmf) and 59.8–61.2% (dmmf), respectively for Raniganj coals and, 0.5–1.1%, 16.7–32.9%, 20.7–22.0% (dmmf) and 78.0–79.3% (dmmf), respectively for Barakar coals. Carbon content is distinct for the suites of coal, 79.2–85.4% and 85.6–92.0% for Raniganj and Barakar coals, respectively. The vitrinite reflectance for the Raniganj coals ranges 0.53–0.72% and the Barakar coals ranges 1.09–1.23%. Based on the chemical composition and vitrinite reflectance value Raniganj coals belongs to high volatile bituminous type, whereas Barakar coals belongs to high to medium volatile bituminous type. Such variation in composition and maturity is mainly attributed to the variation in precursor organic matter as well as the basinal and thermal history of the sub-basins under consideration.H/C atomic ratio of the Raniganj and Barakar coals varies between 0.65 and 0.80 and 0.51–0.72 and O/C atomic ratio varies between 0.05 and 0.13 and 0.01–0.07, respectively. Coals of both the Raniganj and Barakar formations are mostly of kerogen Type-III with Raniganj coals falling in wet gas maturity stage approaching early-thermogenic methane generation whereas Barakar coals falling in condensate gas stage approaching peak-thermogenic methane generation. The Langmuir volume ranges from 9.3–21.8 cc/g (daf) for Raniganj coals and 21.1–29.1 cc/g (daf) for Barakar coals. Sorption capacity for the set of coals shows a strong rank dependency and increase with corresponding increase in rank down the stratigraphic column. Methane sorption capacity shows positive relationship with carbon content and vitrinite reflectance, and negative relationship with moisture content, ash and volatile matter. Moisture effect is more prominent in low rank Raniganj coals. The adsorption capacity shows a strong positive relation with vitrinite content and a moderate negative relation with inertinite content for both the Raniganj and Barakar coals, which may be attributed to dominancy of micropores in vitrinites with rank enhancement. The multiple regression analysis shows that the moisture is the main predictor of the VL, and the interaction of moisture with ash and reflectance mainly control the sorption capacity. A predictive model equation is developed for determination of sorption for Damodar basin coals from carbon, ash and moisture data.

Estudo Analítico Aplicado ao Procedimento de Isolamento do Querogênio em Amostras de Rochas com Potencial Gerador de Hidrocarbonetos

O presente trabalho teve como objetivo contribuir com a otimizacao da tecnica para o isolamento do querogenio em rochas sedimentares com altos teores de materia orgânica soluvel, por meio de testes experimentais visando a limpeza das amostras. As amostras de rocha utilizadas foram folhelhos negros da Formacao Irati, ricos em materia orgânica e com potencial para geracao de hidrocarbonetos. Um planejamento experimental do tipo fatorial foi proposto, para a lavagem das amostras de rocha com a utilizacao de um solvente orgânico (diclorometano) em sistema Soxhlet. Foram estabelecidas relacoes quimiometricas com dois niveis de interacao entre as variaveis (22): massa da amostra da rocha (variando de 20 a 40 g) e tempo de lavagem no diclorometano (variando de 0 a 56 h). O planejamento experimental adotado gerou resultados qualitativos, obtidos por meio de uma avaliacao visual, relacionada a formacao de um anel de querogenio e a fluorescencia observada nas lâminas palinofaciologicas. Os resultados dos testes confirmaram a eficiencia da eliminacao de hidrocarbonetos livres utilizando o sistema Soxhlet, quando amostras com teores altos de hidrocarbonetos livres (ate 4 mg HC/g rocha, aproximadamente) foram submetidas ao valor minimo de massa (20 g) e ao tempo maximo de lavagem (56 h), nos quais o anel de querogenio foi formado em todas as amostras. Com essa mesma configuracao de massa e tempo, as lâminas palinofaciologicas nao apresentaram interferencia dos hidrocarbonetos na fluorescencia dos componentes orgânicos. Portanto, concluiu-se que quanto maior o tempo de lavagem e menor a massa utilizada das amostras, melhores foram os resultados obtidos.

Petrography and source rock potential of Chia Gara Formation (Late Jurassic\u2013Early Cretaceous) in Northern Iraq and Kurdistan Region

The petrographic characteristics and petroleum potential of Chia Gara Formation (Late Jurassic–Early Cretaceous; Tithonian–Berriasian) in Northern Iraq are studied. In order to find out the disparity of Chia Gara Formation in different tectonic zones, two outcrops (Banik and Barsarin sections) and well-Aj-12 were used for this study. In general, the Chia Gara Formation is lithologically composed of black shale, thin-bedded brown argillaceous limestone, thin to medium yellowish limestone. Petrographic study shows that the matrix is mainly composed of micrite, and various diagenetic processes had influenced limestones of Chia Gara Formation, such as neomorphism, dissolution, calcification, cementation and compaction. Fracture, vuggy and moldic are common types of porosity that were observed in this study. However, porosity was later destroyed by some diagenetic processes. The destruction of porosity resulted in considerably low permeability. In addition to petrography, the source rock potential of Chia Gara Formation was also studied. The average values for Total Organic Carbon in percentage (TOC%) of the formation were 1.70, 3.40 and 0.89 for Barsarin, Banik and Aj-12 sections, showing good, very good, and fair organic carbon content, respectively. The pyrolysis executed for studied samples revealed that kerogen type of Chia Gara Formation in Banik section and well Aj-12 belongs to type-II and type-III kerogens, whereas Barsarin section belongs to type-III and type-IV kerogens. The plot of TOC% versus generation potential (S1 + S2) indicated poor to very good potential of hydrocarbon generation for studied samples. The values of the Tmax (the temperature that results in the maximum release of hydrocarbons (S2) during pyrolysis program) suggested that the organic matter in Banik and Barsarin sections is in mature stage, whereas it is thermally immature (or late immature) in well Aj-12. Vitrinite reflectance (R%) also indicated Oil Window to Early Gas Window in Barsarin, Oil Window in Banik, and Early Oil Window in Aj-12. This study revealed that the studied sections from different tectonic zones show slightly different stages of thermal maturity. The high thermal maturity in Barsarin area can be resulted in different type of kerogen compared to the other sections.

Controls on amorphous organic matter type and sulphurization in a Mississippian black shale

Paleoredox proxies (Fe speciation, trace element and δ34Spy) integrated with sedimentological and palynological observations link the distribution and type of particulate organic matter (OM) preserved to hydrocarbon source rock potential. In the Mississippian Bowland Shale Formation (Lancashire, UK), particulate OM is dominated by “heterogeneous” amorphous OM (AOM), primarily “sharp-edged, pellet-like” (AOMpel) and “heterogeneous, granular” (AOMgr) types. AOMpel is abundant in muds deposited under anoxic and moderately to highly sulphidic conditions and most likely represents the fecal minipellets of zooplankton and/or pellets of macro-zooplankters. We recognize two intervals, “A” and “B,” which exhibit Sorg/TOC > 0.04, suggesting a bulk Type II-S kerogen composition. The Interval A palynofacies is typified by pyritized AOMpel (AOMpyr) particles that contain high-relief organic spheres surrounding individual pyrite framboids, within each AOMpyr particle. These textures are interpreted as sulphurized OM local to pyrite framboids (Sorg-PF). Sorg-PF is rarely observed in Interval B, and absent in all other samples. Redox oscillation between ferruginous and euxinic conditions during early diagenesis of Interval A likely promoted S cycling in microenvironments surrounding pyrite framboids, which generated reactive S species and reactive OM required for sulphurization. Early diagenetic redox oscillation processes were apparently triggered by relative sea level fall, associated with an increased supply of FeHR from adjacent shelves into the basin. Interval B represents deposition during the late stages of basin infill and transition from anoxic to (sub)oxic bottom waters, where AOMpel is replaced by AOMgr as the dominant type of AOM. A large particle diameter at the limit of the mesh size (500 μm), sheet-like, fragmented character, and presence of candidate organic sheaths suggests AOMgr at least partially represent fragments of benthic microbial mats, probably as sulphide-oxidizers. A ternary plot of AOMpel + AOMpyr versus AOMgr versus spores + phytoclasts links the observed palynofacies to bottom and pore water redox conditions, water column productivity and proximity to fluvial (deltaic) supply of spores and phytoclasts. These variables were moderated by changing basin accommodation, driven primarily by eustatic sea level fluctuation. A sequence-stratigraphic control on AOM type and sulphurization is important for understanding the link between source rock heterogeneity and the timing of hydrocarbon generation and expulsion from this source rock.

Petroleum geochemical properties of the oil shales from the Early Cretaceous Garau Formation, Qalikuh locality, Zagros Mountains, Iran

A suite of petroleum geochemical techniques including Rock-Eval VI pyrolysis, carbon analyzer, kerogen petrography and palynofacies, vitrinite reflectance (VRr), elemental analysis of kerogen (CHONSFe), gas chromatography (GC), gas chromatography–mass spectrometry (GC–MS), pyrolysis ((PY)-GC) and carbon isotope (δ13C) analyses were performed on 123 outcrop samples from 10 locations to characterize the properties of organic matter and the petroleum potential of the oil shales from the Early Cretaceous Garau Formation at Qalikuh locality in the High Zagros (Iran). To characterize the mineralogy and chemistry of the oil shales X-ray diffraction (XRD) and X-ray fluorescence (XRF) were performed.Together with our previous work (Rasouli et al., 2015), this is the first study in which organic geochemical and petrographical investigations on the Qalikuh oil shales were performed. Total organic carbon (TOC) content of the oil shales varies from 3.83 to 26.4 wt%, with a mean value of 16.5 wt%, suggesting excellent TOC content. The mean value of hydrogen index (HI = 557 mg HC/g TOC) and petroleum potential (S2 = 89 mg HC/g rock) for the oil shales is high, indicating the presence of highly oil-prone organic matter. Elemental analysis of kerogen shows the oil shales are predominantly enriched in Type II-S kerogen. The results of kerogen microscopy observations reveal that homogenous bitumen (as widespread cement by impregnation) and amorphous organic matter are the main organic components. The oil shales of the Garau Formation are mainly consisting of calcite minerals and therefore they are classified as organic-rich/highly bituminous limestone. Additional data from molecular geochemistry and biomarker parameters of GC and GC–MS (e.g. CPI, Pr/Ph, Pr/nC17, Ph/nC18, DBT/Phen and C29/C27 20R sterane) as well as carbon isotope data of extracted bitumen confirm the presence of marine Type II kerogen. These data also show the oil shales were deposited within a marine carbonate environment under anoxic/euxinic conditions.Based on equivalent VRr, elemental analysis, microscopy evidence and biomarker maturity parameters the investigated oil shales from the Garau Formation are early mature and located in the oil generation window. The revised oil-yield calculation from Fischer Assay results confirms the occurrence of moderate to good commercial oil shales with oil yield of 83 l/ton rock on average. Moreover, preliminary analyses of PY-GC data indicate that the Qalikuh oil shales have also very good shale gas potential at over-mature state (i.e. VRr >1.3%).

Stable isotope reversal and evolution of gas during the hydrous pyrolysis of continental kerogen in source rocks under supercritical conditions

Semi-closed hydrous pyrolysis experiments were conducted to investigate the isotopic evolution of shale gas produced from continental organic-rich shales with increasing thermal maturity and prospecting potential. The δ13C values of methane, ethane, propane and n-butane became heavier with increasing thermal maturity and showed good relationships with vitrinite reflectance (VR). Gases expelled from type-I, type-II, and type-III kerogens followed the normal carbon sequence (δ13CC1 < δ13CC2 < δ13CC3 < δ13CnC4) and the hydrogen isotopic sequence (δ2HC1 < δ2HC2 < δ2HC3 < δ2HnC4 < δ2HiC4) among the alkanes at VRs lower than 2.14% Ro, 2.42% Ro, and 1.87% Ro respectively. The isotopically reversed gases (δ13CC1 < δ13CC2 < δ13CnC4 < δ13CC3) were observed in type-I kerogen with a VRs above 2.14% Ro and in type-II kerogen with a VR above 2.42% Ro. In type-III kerogen, isotopically reversed gases (δ13CC1 < δ13CnC4 < δ13CC3 < δ13CC2) were observed with a VR above 2.94% Ro. These results suggest four stages in the stable carbon isotope reversal of ethane, propane, and n-butane with increasing maturity. The isotopically reversed gases (δ13CC1 < δ13CC2 < δ13CnC4 < δ13CC3) may represent lower maturity and higher productivity shale gas than the isotopically reversed gases (δ13CC1 < δ13CnC4 < δ13CC3 < δ13CC2), indicating that continental type-I kerogen has the highest potential productivity for shale gas, and continental type-III kerogen has the lowest. Stable hydrogen isotope composition did not respond to the stable carbon isotope reversal in isotopically reversed gases. We suggest that indigenous generation and mixing may be the dominant mechanisms responsible for the stable carbon isotope reversal, and adsorption/desorption during hydrocarbon expulsion may promote the stable isotope reversal under semi-closed conditions. Overall, these results suggest that this study is an important contribution to continental shale gas exploration.

Petrographic and Geochemical Study of Gurha Lignites, Bikaner Basin, Rajasthan, India: Implications for Thermal Maturity, Hydrocarbon Generation Potential and Paleodepositional Environment

Abstract In the present study an attempt has been made to characterize the Gurha lignites employing petrographic and geochemical techniques on a large number of lignite samples. The data generated has been discussed to understand the hydrocarbon generation potential as well as the evolution of the paleomires of these lignites. The present investigation indicates that these lignites are mainly dominated by the huminite followed by inertinite and liptinites occurs in meager concentration. The huminite reflectance values rank the Gurha lignite as a low-rank B lignite. Petrographic result indicates these lignites are thermally immature in nature and comprised of Type-III kerogen and may generate only gas on maturation which is further supported by the rock-eval pyrolysis. The plots of rock eval data also indicates the same. The GI and TPI as well as GWI and VI values and the petrography-based facies critical models indicate that these lignites originated mostly under wet forest swamp condition. The microscopic constituents have also shown that these lignites are from herbaceous plants in wet forest swamp environment and ombrotrophic hydrological condition. The presences of framboidal pyrite in the study area infer the marine influence which also supported by the presence of high sulphur content.

Influence of coal composition and maturity on methane storage capacity of coals of Raniganj Coalfield, India

Methane generation primarily depends on the quantity, type and structure of kerogens and is controlled by temperature to which the precursor material is subjected over the geologic time whereas the gas-in-place depends on the storage capacity and burial history. The Raniganj Coalfield of India hosts significant reserves of good quality coals of Permian age belonging to two formations, Barakar and Raniganj. The adsorption characteristics of the nine regional (R-I to R-IX) and three local seams from Raniganj Formation of south-western part of the coalfield is thoroughly investigated in the light of reflectance, petrography and chemical composition for their CBM potential. Ash (A), moisture (M), volatile matter (VM) and fixed carbon (FC) of these coals range within 12.8–37.3%, 1.1–4.0%, 31.7–51.1% (daf) and 48.9–68.3% (daf), respectively. Carbon (C) varies within the range 77.0–86.8% (dmmf) and reflectance (Rr) within 0.62–0.87%. The coals are high volatile gas prone orthohydrous bituminous type. Both C and Rr increase, and M and VM decrease with depth. Vitrinite ranges mostly within 64.5–85.5%, inertinite 4.8–24.1% and liptinite below 15%, on mineral matter free basis. Most of the samples fall in Type-III kerogen and few are transitional to Type-II and Type-III.Gas content of the samples lies between 3.08 and 14.96 cc/g, on daf basis and generally increases with depth. Langmuir volume (VL) for the coals varies between 17.4 and 29.8 cc/g (daf) and exhibits a moderately positive linear relationship with increase in depth (R2 = 0.58). Reflectance shows a strong linear positive relationship (R2 = 0.70) with Langmuir volume indicating the development of additional micropores with rank enhancement, thereby providing more surface area for adsorption. Gas content results are encouraging though the seams are considerably undersaturated. A very good correlation is observed for the combined effect of ash, moisture and carbon on volume adsorbed for the studied coals and can be used to predict adsorption capacity from compositional data.

Organic geochemical characteristics of Nagaur lignites, Rajasthan, India, and their implication on thermal maturity and paleoenvironment

ABSTRACTLignite samples from Nagaur district, Rajasthan, have been collected for petrographic and organic geochemical analyses following the pillar sampling method. The reflectance of Eu-Ulminite-B ranges from 0.20 to 0.49 with a mean of 0.33%Ro, putting them as “Low-Rank B” coal. Hydrogen index values imply type-III kerogen, while the values of Tmax (402 to 411°C) indicate that these coals are thermally immature. Gas chromatography data reveal the presence of n-alkanes from C14 to C33 with a predominance of odd n-alkanes over the even homologues. Pristane vs. phytane ratio indicates anoxic conditions during the deposition of the organic matter. Saturated fractions of studied lignites suggest a contribution from both conifers and angiosperms as source vegetation.

The effect of pressure and hydrocarbon expulsion on hydrocarbon generation during pyrolyzing of continental type-III kerogen source rocks

In order to define the roles of water and lithostatic pressure in petroleum formation of continental type-III kerogen source rocks, semi-closed hydrous pyrolysis experiments were conducted under with 50–1200 bar water pressure and 125–2000 bar lithostatic pressure at 480 °C. Our results will be of great benefit to the exploration of shale gas and deep petroleum in China. Increasing water pressure from 50 to 325 bar did not affect the yields of gaseous hydrocarbons, oil and bitumen, but increasing water pressure leads the more oil and less gaseous hydrocarbons from continental type-III kerogen in the 325–1200 bar water pressure range under semi-closed conditions. The decreasing yields of gaseous hydrocarbons, dryness of gaseous hydrocarbons and primary hydrogen together confirm that increasing water pressure promotes the primary reaction but decreases the cracking rate of oil. The decreasing values of S2, HI and H/C in the pyrolysed samples confirm that high water pressure can increase the efficiency of hydrocarbon generation from continental type-III kerogen, while the maturation of kerogen correspondingly increases as shown by increasing values of VR and Tmax. In the 125–625 bar lithostatic pressure range, oil cracking and primary reaction of type-III kerogen may have contributed to the decreasing effect of hydrocarbon expulsion. The increasing hydrogen and gaseous hydrocarbon yields also confirm that the cracking of oil is enhanced within this pressure range. The decreasing trends of oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was reduced by the high lithostatic pressure in the 625–2000 bar pressure range. The increasing values of S2, HI and H/C, and decreasing values of VR and Tmax of pyrolysed samples confirm the retardation effect of highlithostatic pressure on the efficiency of hydrocarbon generation and maturation. In addition, the results also indicate that expelling hydrocarbons strongly promotes further hydrocarbon generation and retards the cracking of oil from continental type-III kerogen in source rocks.

Late Jurassic bituminous shales from Marib oilfields in the Sabatayn Basin (NW Yemen): Geochemical and petrological analyses reveal oil-shale resource

In this study, bituminous shale samples were collected from Late Jurassic sedimentary section in the Marib oilfields to study their petrologic and organic geochemical properties. The results of this study indicate that the Late Jurassic bituminous shales can be considered as an oil-source rocks in the Sabatayn Basin (NW Yemen). The analyzed Late Jurassic shales have high organic matter (TOC up to 10%) content of kerogen Types I/II. These kerogen types in the analyzed samples are consistent with the high dominance of alginite and amorphous organic matter. Open pyrolysis–gas chromatography results are generally consistent with the Rock-Eval results and further indicate that the analyzed shale samples contain Types I/II and II-S kerogen and generally can produce paraffinic oils with low to high wax content. Type II-S kerogen can produce oil with high sulphur content at low maturity level. The maturity data reflect immature and very early maturity stages of petroleum formation of the Late Jurassic bituminous shales. Therefore, the kerogen types in the Late Jurassic bituminous shales has not been altered by thermal maturity for oil generation, thus, artificial heating is required of kerogen cracking generate significant oil.

Organic geochemistry of the Middle-Upper Jurassic Naokelekan Formation in the Ajil and Balad oil fields, northern Iraq

Sixteen organic-rich argillaceous limestone and black shale samples from three wells with up to 16 wt% TOC (average 9.32 wt%) from the Middle–Upper Jurassic Naokelekan Formation in the west Zagros Basin of northern Iraq were evaluated as source rocks. Both organic geochemical and molecular data indicate an open marine environment at the time of deposition, leading to accumulation of Type-II and Type-III kerogen with varying oil and gas generation potential. The predominance of short-chain n-alkanes (n-C13–n-C19), and C27 and C29 steranes, and absence of oleanane confirm the dominantly planktonic/bacterial and algal origin of the organic matter. Organic richness, low Pr/Ph, and high C35/C34 homohopane ratios suggest alternating anoxic to suboxic depositional conditions. Biomarker distributions are consistent with sporadic anoxia, with unequivocal evidence for stratification of the water column and hypersalinity. The 22S/(22S + 22R) ratios for C32 homohopanes, moretane/hopane, and C29 sterane 20S/(20S + 20R) and ββ/(ββ+αα) ratios vary irregularly, whereas the C27 diasteranes, Ts/(Tm + Ts), triaromatic cracking and MDR ratios vary substantially and increase with burial depth among different homologues within the same sample set, indicating the threshold to peak of the oil-generation window. Based on hierarchical cluster analysis (HCA) and principal component analysis (PCA) of 13 selected source-related biomarker ratios, the source rock extracts have been divided into three groups: Group-1 from the Ba-1 well, Balad oil field, and Groups-2 and -3 from the Aj-8 and Aj-12 wells, respectively, in the Ajil oil field.

Hydrocarbon generation and potential in continental organic-rich shales at the highly-mature stage, as determined by hydrous pyrolysis under supercritical conditions

Hydrous pyrolysis experiments were conducted to assess hydrocarbon generation and potential in three continental organic-rich shales at the highly-mature stage. The results of this study have important implications for deep petroleum exploration in China. The calcareous shale dominated by type-I kerogen reached its peak oil generation at a vitrinite reflectance (VR) of 1.5 %Ro, and entered the major stage of gas generation at a VR ranging from 1.50 to 2.44 %Ro. The high HI, low S2 and low atomic H/C ratio revealed that the calcareous shale has some potential for hydrocarbon generation at a VR greater than 2.44 %Ro. The mudstone with type-II kerogen reached its peak oil generation at a VR of 2.5 %Ro. The high atomic H/C ratio, but low HI and S2 indicated that mudstone may retain some hydrocarbon potential. The carbonaceous mudstone dominated by type-III kerogen had still not reached its peak of hydrocarbon generation at a VR of 3.12 %Ro. The low dryness of the gaseous hydrocarbon yields shows that the carbonaceous mudstone was still in the primary gas generation stage. The high values of S2 and atomic H/C fraction, but low HI, revealed that the carbonaceous mudstone may retain a large hydrocarbon generation potential at higher maturity stages. Our results suggested that the continental type-I and -II kerogen may have potential for shale gas and deep petroleum generation, while the continental type-III kerogen retained good potential for yielding deep natural gas.

Geochemical characteristics, depositional environment and hydrocarbon generation modeling of the upper cretaceous Pakawau group in Taranaki Basin, New Zealand

The oil, gas and condensate province of the Upper Cretaceous to Cenozoic Taranaki Basin is very important as it has become the sole commercially-producing sedimentary basin in New Zealand. An understanding of burial/thermal geo-histories of Taranaki Basin is essential for modeling hydrocarbon generation. In the present study, data from subsurface samples from selected wells have been analyzed and interpreted for characterizing source rock of the Pakawau Group along with thermal geohistory of the basin. The Upper Cretaceous Pakawau Group, made up of Rakopi (87-75 Ma) and North Cape (75-65 Ma) formations, is the eldest and most prolific organic rich hydrocarbon source rock in the basin. Their lithologies vary between carbonaceous mudstone and coal from alluvial to coastal plain depositional environments with marginal marine influence. Most samples that are interpreted contain kerogen Types II and II-III, with few samples of Type-III kerogen. This is validated by the biomarkers results, where the assessed data shows that the organic source ranges from terrestrial to marine origin. The Pakawau Group source is immature to mature, as reflected by the distribution of vitrinite reflectance (%Ro), pyrolysis Tmax from pyrolysis data and biomarkers data. Vitrinite reflectance distribution shows that the Rakopi Formation is mostly within the mature oil window for hydrocarbon generation with values ranging generally between 0.5% and 0.95% Ro. Using two selected wells, the models have been interpreted to generate hydrocarbons from the Pakawau Group between Upper Paleocene and Middle Eocene. Interpretations of the burial models confirm that hydrocarbons of Pakawau Group has not yet attained peak generation and is still being expelled from the source rock to-date.

A study on assessment of hydrocarbon potential of the lignite deposits of Saurashtra basin, Gujarat (Western India)

In the present investigation, Bhavnagar lignites of the Saurashtra basin (Gujarat) have been studied to assess their hydrocarbon generating potential. The samples of upper as well as lower lignite seams have been studied through microscopy and subjected to various chemical analyses viz. proximate analysis, ultimate analysis and Rock-Eval Pyrolysis. These lignites have high moisture and low to moderate ash yield but are characterized by high volatile matter. Petrographically they comprise predominantly of huminite group maceral while liptinite and inertinite groups occur in subordinated amount. Huminite is chiefly composed of detrohuminite and telohuminite. The Tmax (av. 416.23 °C) and huminite reflectivity (0.28%–0.30%) indicate a low degree of maturity for these lignites which is also substantiated by the Tmax versus hydrogen index plot. The organic matter is subjugated by kerogen Type-III with a potential to expel hydrocarbon on liquefaction. Study further reveals that the fixed hydrocarbon is several folds higher than the free hydrocarbons. Being high in reactive maceral content, a high ‘conversion’ and good ‘oil yield’ values for these lignites were observed. Thus, the empirically derived values match well with those obtained through the experimental values of Rock-Eval Pyrolysis and validate their hydrocarbon generating potential.

Generation and expulsion history of oil-source rock (Middle Jurassic Sargelu Formation) in the Kurdistan of north Iraq, Zagros folded belt: Implications from 1D basin modeling study

Middle Jurassic Sargelu Formation is an important oil-source rock in the Iraqi Kurdistan oilfields, northern Zagros Fold Belt. The Sargelu source rock is characterised by high organic matter and sulphur content with Type II-S kerogen, which can be expected to generate oil at low maturity stages.A 1D basin modelling was performed by integrating geological and geochemical data of the Sargelu source rock from six wells in the Kurdistan region, north Iraq. The basin modelling results was used to reconstruct the burial and thermal history and to simulate and predict the timing of petroleum generation and expulsion for the Middle Jurassic Sargelu source rock. Burial/thermal history models indicate that the Sargelu source rock had passed the peak-oil generation window during the Late Eocene to Late Miocene. Onset of oil-generation began during the Middle Eocene - Late Miocene (51-11 Ma), whereas the maximum rates of oil with limited gas were generated during the Late Eocene to Late Miocene (52-10 Ma). The models also show that the oil was expelled from the Sargelu source rock since Late Eocene to present-day (44-0 Ma), with transformation ratio higher than 50%. The subsequent high transformation ratio higher than 80% suggests that the generated oil was cracked to gas during the Early Oligocene and continued to present day. These basin modeling results also suggest that the Sargelu Formation acts as an effective oil-source where significant amount of petroleum is expected to be generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region.