Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.     

Fragment of the chemical structure of type II and II-S kerogen in the Upper Jurassic and Upper Devonian formations of the East European Platform

A model is proposed for a fragment of the chemical structures of the geopolymers based on elemental analysis and the study of the composition of the pyrolysis products of kerogen from the Upper Jurassic and Devonian formations in the East European Platform. The S_org/C ratio in kerogen from oil shales from J₃v₂ is 0.4 or higher, and this kerogen belongs to type II-S, while kerogen from the Domanik rocks does not contain S and belongs to type II. The composition of the pyrolysis products of the Upper Jurassic kerogen testifies to the presence of polysulfur-bound structures in this geopolymer, whose thermolysis results in disulfuric cyclic compounds. No structures of this type are contained in Domanik kerogen. Oxygen-bearing groups in J₃v₂ kerogen are thought to be partly concentrated on simple-ether bonds, whereas D₃dm kerogen is likely dominated by compound-ether and carboxyl structures. Nitrogen-bearing structures in kerogen from Upper Jurassic and Domanik formations are of different genesis: while nitrogen-bearing structures in Jurassic kerogen are mostly aminoacids, Domanik kerogen contains chitin derivatives.     

Comparison of natural gases accumulated in Oligocene strata with hydrous pyrolysis gases from Menilite Shales of the Polish Outer Carpathians

This study examined the molecular and isotopic compositions of gases generated from different kerogen types (i.e., Types I/II, II, IIS and III) in Menilite Shales by sequential hydrous pyrolysis experiments. The experiments were designed to simulate gas generation from source rocks at pre-oil-cracking thermal maturities. Initially, rock samples were heated in the presence of liquid water at 330 °C for 72 h to simulate early gas generation dominated by the overall reaction of kerogen decomposition to bitumen. Generated gas and oil were quantitatively collected at the completion of the experiments and the reactor with its rock and water was resealed and heated at 355 °C for 72 h. This condition simulates late petroleum generation in which the dominant overall reaction is bitumen decomposition to oil. This final heating equates to a cumulative thermal maturity of 1.6% R_r, which represents pre-oil-cracking conditions. In addition to the generated gases from these two experiments being characterized individually, they are also summed to characterize a cumulative gas product. These results are compared with natural gases produced from sandstone reservoirs within or directly overlying the Menilite Shales. The experimentally generated gases show no molecular compositions that are distinct for the different kerogen types, but on a total organic carbon (TOC) basis, oil prone kerogens (i.e., Types I/II, II and IIS) generate more hydrocarbon gas than gas prone Type III kerogen. Although the proportionality of methane to ethane in the experimental gases is lower than that observed in the natural gases, the proportionality of ethane to propane and i-butane to n-butane are similar to those observed for the natural gases. δ¹³C values of the experimentally generated methane, ethane and propane show distinctions among the kerogen types. This distinction is related to the δ¹³C of the original kerogen, with ¹³C enriched kerogen generating more ¹³C enriched hydrocarbon gases than kerogen less enriched in ¹³C. The typically assumed linear trend for δ¹³C of methane, ethane and propane versus their reciprocal carbon number for a single sourced natural gas is not observed in the experimental gases. Instead, the so-called “dogleg” trend, exemplified by relatively ¹³C depleted methane and enriched propane as compared to ethane, is observed for all the kerogen types and at both experimental conditions. Three of the natural gases from the same thrust unit had similar “dogleg” trends indicative of Menilite source rocks with Type III kerogen. These natural gases also contained varying amounts of a microbial gas component that was approximated using the Δδ¹³C for methane and propane determined from the experiments. These approximations gave microbial methane components that ranged from 13–84%. The high input of microbial gas was reflected in the higher gas:oil ratios for Outer Carpathian production (115–1568 Nm³/t) compared with those determined from the experiments (65–302 Nm³/t). Two natural gas samples in the far western part of the study area had more linear trends that suggest a different organic facies of the Menilite Shales or a completely different source. This situation emphasizes the importance of conducting hydrous pyrolysis on samples representing the complete stratigraphic and lateral extent of potential source rocks in determining specific genetic gas correlations.     

Source rock potential of selected Cretaceous shales,Orange Basin,South Africa

Twenty Cretaceous shale samples from two wells in the Orange Basin of South Africa were evaluated for their source rock potential. They were sampled from within a 1400 m-thick sequence in boreholes drilled through Lower to Upper Cretaceous sediments. The samples exhibit total organic carbon (TOC) content of 1.06–2.17%; Rock-Eval S2 values of 0.08–2.27 mg HC/g; and petroleum source potential (SP), which is the sum of S1 and S2, of 0.10–2.61 mg HC/g, all indicating the presence of poor to fair hydrocarbon generative potential. Hydrogen index (HI) values vary from 7 to 128 mg HC/g organic carbon and oxygen index (OI) ranges from 37 to 195 mg CO₂/g organic carbon, indicating predominantly Type III kerogen with perhaps minor amounts of Type IV kerogen. The maturity of the samples, as indicated by T _max values of 428–446°C, ranges from immature to thermally mature with respect to oil generation. Measured vitrinite reflectance values (%Ro) of representative samples indicate that these samples vary from immature to mature, consistent with the thermal alteration index (TAI) (spore colour) and fluorescence data for these samples. Organic petrographic analysis also shows that amorphous organic matter is dominant in these samples. Framboidal pyrite is abundant and may be indicative of a marine influence during deposition. Although our Rock-Eval pyrolysis data indicate that gas-prone source rocks are prevalent in this part of the Orange Basin, the geochemical characteristics of samples from an Aptian unit at 3318 m in one of the wells suggest that better quality source rocks may exist deeper, in more distal depositional parts of the basin.     

Gas generation and expulsion characteristics of Middle–Upper Triassic source rocks,eastern Kuqa Depression,Tarim Basin,China: implications for shale gas resource potential

Frontier exploration in the Kuqa Depression, western China, has identified the continuous tight-sand gas accumulation in the Lower Cretaceous and Lower Jurassic as a major unconventional gas pool. However, assessment of the shale gas resource in the Kuqa Depression is new. The shale succession in the Middle–Upper Triassic comprises the Taliqike Formation (T₃t), the Huangshanjie Formation (T₃h) and the middle–upper Karamay Formation (T_2–3k), with an average accumulated thickness of 260 m. The high-quality shale is dominated by type III kerogen with high maturity and an average original total organic carbon (TOC) of about 2.68 wt%. An improved hydrocarbon generation and expulsion model was applied to this self-contained source–reservoir system to reveal the gas generation and expulsion (intensity, efficiency and volume) characteristics of Middle–Upper Triassic source rocks. The maximum volume of shale gas in the source rocks was obtained by determining the difference between generation and expulsion volumes. The results indicate that source rocks reached the hydrocarbon expulsion threshold of 1.1% VR and the hydrocarbon generation and expulsion reached their peak at 1.0% VR and 1.28% VR, with the maximum rate of 56 mg HC/0.1% TOC and 62.8 mg HC/0.1% TOC, respectively. The volumes of gas generation and expulsion from Middle–Upper Triassic source rocks were 12.02 × 10¹² m³ and 5.98 × 10¹² m³, respectively, with the residual volume of 6.04 × 10¹² m³, giving an average gas expulsion efficiency of 44.38% and retention efficiency of 55.62%. Based on the gas generation and expulsion characteristics, the predicted shale gas potential volume is 6.04 × 10¹² m³, indicating a significant shale gas resource in the Middle–Upper Triassic in the eastern Kuqa Depression.     

Study of petroleum generation by pyrolysis—I. Pyrolysis experiments by Rock-Eval and assumption of molecular structural change of kerogen using13C-NMR

Green River shale (Type I kerogen), Yaamba shale (Type II kerogen) and Sarufutsu coal (Type III kerogen) were heated to various temperatures using Rock-Eval. The amount of hydrocarbons generated and weight loss by pyrolysis were measured to obtain a better understanding of petroleum generation. After the pyrolysis experiments, elemental analysis (C, H), vitrinite reflectance (%R_o) measurement, maceral observation, infrared spectroscopy (IR) and¹³C-NMR spectroscopy were carried out on the coal samples. Changes in H/C atomic ratio, IR and NMR spectra indicate that experiments by Rock-Eval resemble those of the natural evolution of kerogen. However, the petrographic changes of the coal show more similarity to coal liquefaction and coking than to natural coalification. Changes in the amount of generated hydrocarbons with increasing maturation show that Type II kerogen produces more hydrocarbons than does Type I when R_o does not exceed 1.1%. Petroleum generation curves for the three samples were concordant with trends in natural systems, and a conceptual model of petroleum generation curve classified into three types is proposed, namely (1) curve of total amount enerated, (2) curve of generation rate, and (3) curve of fluid composition. Changes of IR and NMR spectra after pyrolysis imply that generated hydrocarbons are derived from aliphatic C structures of kerogen macromolecules. Moreover, the difference in genetic potential between Type I and Type III reflects different amounts of aliphatic structures. Type I is assumed to have a simple assemblage (mainly polymethylene carbons), and Type III is assumed to have a more complex variety of structures that are responsible for the difference in generation rates between the two kerogen Types. A quantitative analysis of C species of various bond structure by¹³C-NMR confirms that petroleum generation is the process of bond cleavage of kerogen macromolecules; lower-energy bonds decrease at an earlier stage of reaction, while aromatic carbons with higher bond energies survive to form graphitic structure at postmature stages. Emphasis is placed on the idea that the most important and direct factor in petroleum generation is a change in the molecular structure of kerogen with increasing maturation. NMR and other methods providing information about molecular structures of kerogen will become strong tools for evaluating source rocks and sedimentary basins in the future.     

Carbon isotopes of organic matter from the upper Jurassic oil shales from the Volgian-Pechora shale province and its accumulation mechanisms

The isotopic composition of carbon from the organic matter of late Jurassic oil shales from the Volgian-Pechora shale province is studied. The existence of a dependence between C_org content in the rock and the isotopic composition of kerogen carbon is ascertained. The content of the heavy carbon isotope increases with increasing C_org. This dependence is accounted for by the progressive accumulation of isotopically heavy hydrocarbons of the initial organic matter due to sulfurization. The data on the isotopic composition of individual n-alkanes of bitumen in the rocks and the data on the absence of isotopic fractionation between thermobitumen and the residual kerogen from oil shales from the Volgian-Pechora shale province obtained by treating shale in an autoclave in the presence of water are presented first in this paper.     

Source Rock Characterization and Petroleum Systems in North Ghadames Basin,Southern Tunisia

This paper presents geochemical analysis of drilled cutting samples from the OMZ‐2 oil well located in southern Tunisia. A total of 35 drill‐cutting samples were analyzed for Rock‐Eval pyrolysis, total organic carbon (TOC), bitumens extraction and liquid chromatography. Most of the Ordovician, Silurian and Triassic samples contained high TOC contents, ranging from 1.00 to 4.75% with an average value of 2.07%. The amount of hydrocarbon yield (pyrolysable hydrocarbon: S2b) expelled during pyrolysis indicates a good generative potential of the source rocks. The plot of TOC versus S2b, indicates a good to very good generative potential for organic matter in the Ordovician, Silurian and Lower Triassic. However, the Upper Triassic and the Lower Jurassic samples indicate fair to good generative potential. From the Vankrevelen diagram, the organic matter in the Ordovician, Silurian and Lower Triassic samples is mainly of type II kerogen and the organic matter from the Upper Triassic and the Lower Jurassic is dominantly type III kerogen with minor contributions from Type I. The thermal maturity of the organic matter in the analyzed samples is also evaluated based on the T_max of the S2b peak. The Ordovician and Lower Silurian formations are thermally matured. The Upper Silurian and Triassic deposits are early matured to matured. However, Jurassic formations are low in thermal maturity. The total bitumen extracts increase with depth from the interval 1800–3000 m. This enrichment indicates that the trapping in situ in the source rocks and relatively short distance vertical migration can be envisaged in the overlying reservoirs. During the vertical migration from source rocks to the reservoirs, these hydrocarbons are probably affected by natural choromatography and in lower proportion by biodegradation.     

The effect of oil expulsion or retention on further thermal degradation of kerogen at the high maturity stage: A pyrolysis study of type II kerogen from Pingliang shale,China

High maturity oil and gas are usually generated after primary oil expulsion from source rocks, especially from oil prone type I/II kerogen. However, the detailed impacts of oil expulsion, or retention in source rock on further thermal degradation of kerogen at the high maturity stage remain unknown. In the present study, we collected an Ordovician Pingliang shale sample containing type II kerogen. The kerogens, which had previously generated and expelled oil and those which had not, were prepared and pyrolyzed in a closed system, to observe oil expulsion or oil retention effects on later oil and gas generation from kerogen. The results show that oil expulsion and retention strongly impacts on further oil and gas generation in terms of both the amount and composition in the high maturity stage. Gas production will be reduced by 50% when the expulsion coefficient reaches 58%, and gas from oil-expelled kerogen (less oil retained) is much drier than that from fresh kerogen. The oil expulsion also causes n-alkanes and gas compounds to have heavier carbon isotopic compositions at high maturity stages. The enrichment of ¹³C in n-alkanes and gas hydrocarbons are 1‰ and 4–6‰ respectively, compared to fresh kerogen. Oil expulsion may act as open system opposite to the oil retention that influences the data pattern in crossplots of δ¹³C₂–δ¹³C₃ versus C₂/C₃, δ¹³C₂–δ¹³C₃ versus δ¹³C₁ and δ¹³C₁–δ¹³C₂ versus ln(C₁/C₂), which are widely used for identification of gas from kerogen cracking or oil cracking. These results suggest that the reserve estimation and gas/source correlation in deep burial basins should consider the proportion of oil retention to oil expulsion the source rocks have experienced.     

Differences in the mode of incorporation and biogenicity of the principal aliphatic constituents of a Type I oil shale

Compound-specific stable carbon isotope (δ ) measurements on the aliphatic hydrocarbons released from an immature Tertiary oil shale (Göynük, Turkey) via hydropyrolysis, following solvent extraction and a milder hydrogenation treatment, have further highlighted that significant compositional differences may exist between the principal aliphatic constituents of the solvent extractable (bitumen) phase and the insoluble macromolecular network (kerogen) comprising the bulk of sedimentary organic matter. Whilst inputs from diverse sources; including algae, bacteria and terrestrial higher plants, were implied from analysis of solvent-extractable alkanes, the much larger quantities of kerogen-bound n-alkyl constituents released by hydropyrolysis had a uniform isotopic signature which could be assigned to (freshwater) algae. Remarkably, the aliphatics bound to the kerogen by relatively weak covalent bonds, liberated via catalytic hydrogenation, appeared to comprise mainly allochthonous higher plant-derived n-alkanes. These results provide further compelling evidence that the molecular constituents of bitumen and, indeed, of low-yield kerogen degradation products, are not necessarily reliable indicators of kerogen biogenicity, particularly for immature Type I source rocks. The isotopic uniformity of aliphatic n-hydrocarbons released by the high-conversion hydropyrolysis step for the ultralaminae-rich Göynük oil shale, lends further support to the theory that selective preservation of highly resistant aliphatic biomacromolecules is an important mechanism in kerogen formation, at least for alginite.     

The shale gas potential of Tournaisian, Visean, and Namurian black shales in North Germany: baseline parameters in a geological context

Carboniferous black mudrocks with known petroleum potential occur throughout Northern Germany. However, despite numerous boreholes exploring for conventional hydrocarbons, the potential for shale gas resources remains uncertain. Therefore, an integrated investigation was conducted to elucidate the shale gas potential for three different Carboniferous facies incorporating baseline parameters from sedimentological and organic-geochemical analyses. Tournaisian–Namurian fine-grained rocks of the Culm-facies, with Type II + III kerogen were deposited in the basin center. TOC contents of up to 7 % occur in the Lower Alum Shale (3.6 % VRr) and up to 6 % in the Upper Alum Shale (4.4 % VRr). Bands of organic-rich black shales, reflecting sea-level variations controlled by global eustatic cycles, occur within the Tournaisian–Visean “Kohlenkalk”-facies north of the Rhenish Slate Mountains and in the Rügen island area. In both areas the organic matter is characterized by a kerogen Type II + III with TOC contents of up to 7 % and maturities of up to 4.2 and 1.8 % VRr, respectively. Black hemipelagites intercalated with coarser-grained silt- and sandstones occur in the Synorogenic Flysch Formation of the Namurian A along the southern basin margin. TOC contents vary from 0.5 to 2.0 % with Type III kerogen dominated organic matter and maturities of up to 2.5 % VRr. The baseline parameters presented in this paper indicate a shale gas potential for the sediments of the Culm-facies on the southern basin margin and of the “Kohlenkalk”-facies in the Rügen area.     

Kerogen based characterization of major gas shales: Effects of kerogen fractionation

Research into the origin and the mode of entrapment and expulsion of natural gas from unconventional plays requires the isolation and separation of kerogen in its purest and most intact form from the rock matrix. This study expands on the comparative analysis of the effects that isolation methods, conservative closed system versus conventional open system, have on kerogen’s elemental, isotopic and physical properties. Four major gas shales, including the Barnett, the Marcellus, the Haynesville and a Polish gas shale, were chosen. In addition, the Monterey shale, though not strictly a gas shale, was included to address the effects on sulfur rich, Type II-S kerogen.Results indicate that the kerogen residues from the conventional open system method showed lower recovery and higher mineral content than those from the conservative closed system method. Differences were manifested in the elemental analysis data, where kerogens isolated using the open system method showed a significant deficit in the organic C, H, O, S and N material balance. Furthermore, the recovered residues show different sulfur content and δ³⁴S composition, most likely attributable to differences in pyrite content. Nevertheless, the relative abundances of the various macerals in the kerogen residues from the same parent shale are not very different; neither was the bulk δ¹³C composition of the recovered residues. This is not particularly surprising, considering that in all the five cases examined in this study, the organic matter was fairly homogeneous.     

Hydrocarbon potential of the Sargelu Formation,North Iraq

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg?HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI?=?3^? to 3⁺, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R₂₈ steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.     

Geochemistry,origin and correlation of crude oils in Lower Cretaceous sedimentary sequences of the southern Mesopotamian Basin,southern Iraq

Thirty one crude oil samples from Lower Cretaceous reservoirs in southern Iraq were analyzed using bulk property and molecular methods to determine their maturity and biomarker characteristics, as well as to obtain information on their respective source rocks. All the oils are unaltered, non-biodegraded, have high sulfur content and API gravity is in the range for light to heavy oil (19–40° API). They are characterized by low Pr/Ph values, even/odd predominance and front-end biased n-alkane distributions. Based on these parameters the oils were generated and expelled from a marine carbonate source rock bearing Type II-S kerogen. Compositional similarities of hopane and sterane biomarkers with those from potential source rocks allowed identification of the Upper Jurassic–Lower Cretaceous Sulaiy and Yamama carbonate succession as the effective source beds. A similar composition of normal and isoprenoid hydrocarbons among the oils suggests an origin from a common source rock. However, biomarker maturity ratios indicate a wide range of maturity. This appears to result from the type of burial history of the source rock, characterized by a slow passage through the liquid window interval during an extended period of geologic time.     

Organic matter in Upper Devonian deposits of the Chernyshev Ridge

The study provides the first data on organic matter from Upper Devonian deposits of the Shar’yu River section (Chernyshev Ridge, Northern Urals). Oil shales from the Middle and Middle–Upper Domanik intervals and carbonaceous shales from the Upper Frasnian intervals were analyzed. The biomarker analysis revealed similar characteristics of organic matter from studied samples and Domanik-facies rocks of the Ukhta area. It was also shown that organic matter from the studied Domanik section is characterized by compositional heterogeneity. The biomarker and stable carbon isotope compositions of bitumen extracts, their fractions, and kerogen of the Middle and Middle–Upper Domanik shales are different from those of the Upper Frasnian shale, which may indicate the variation in depositional setting.     

Biomarker analysis of the upper Jurassic Naokelekan and Barsarin formations in the Miran Well-2, Miran oil field,Kurdistan region,Iraq

The Miran oilfield is one of the new oil fields in Kurdistan region, northern Iraq, located in the Sulaimani Governorate. Twelve Cuttings samples from the Upper Jurassic Naokelekan and Barsarin formations in well Miran-2 were selected for detailed organic geochemical investigations. All the samples were subjected to bitumen extraction in order to study any biomarkers present using gas chromatography-mass spectrometry. The dominance of low-molecular-weight n-alkanes and other calculated parameters indicate a marine source for the organic matter derived from planktonic algal and bacterial precursors deposited under anoxic conditions. The isoprenoids/n-alkanes ratios indicate type II and mixed II/III kerogen for both formations. The type II/III kerogen is characteristic of transitional environment under anoxic to dysoxic conditions as also indicated by the homohopane index for studied samples. More argillaceous carbonate rocks were deposited when reducing conditions were prevalent. Medium to high gammacerane index values in the rock extracts probably indicate a stratified water column during deposition of both formations. The studied samples from both formations have entered peak oil window maturity as reflected from the biomarker ratios from both aliphatic and aromatic fractions of the extracts.     

Distinguishing Cambrian from Upper Ordovician source rocks: Evidence from sulfur isotopes and biomarkers in the Tarim Basin

The reported source rocks for the abundant petroleum in the Tarim Basin, China range from Cambrian to Lower Ordovician and/or Upper Ordovician in age. However, the difference between the two groups of source rocks is not well characterized. In this study, pyrite was removed from eleven mature to over mature kerogen samples from source rocks using the method of CrCl₂ reduction and grinding. The kerogen and coexisting pyrite samples were then analyzed for δ³⁴S values. Results show that the kerogen samples from the Cambrian have δ³⁴S values between +10.4‰ and +19.4‰. The values are significantly higher than those from the Lower Ordovician kerogen (δ³⁴S of between +6.7‰ and +8.7‰), which in turn are generally higher than from the Upper Ordovician kerogen samples (δ³⁴S of between ?15.3 and +6.8‰). The associated pyrite shows a similar trend but with much lower δ³⁴S values. This stratigraphically controlled sulfur isotope variation parallels the evolving contemporary marine sulfate and dated oil δ³⁴S values from other basins, suggesting that seawater sulfate and source rock age have an important influence on kerogen and pyrite δ³⁴S values. The relatively high δ³⁴S values in the Cambrian to Lower Ordovician source rocks are associated with abundant aryl isoprenoids, gammacerane and C₃₅ homohopanes in the extractable organic matter, indicating that these source rocks were deposited in a bottom water euxinic environment with water stratification. Compared with the Upper Ordovician, the Cambrian to Lower Ordovician source rocks show abundance in C₂₈ 20R sterane, C₂₃ tricyclic terpanes, 4,23,24-trimethyl triaromatic dinosteroids and depletion in C₂₄ tetracyclic terpane, C₂₉ hopane. Thus, δ³⁴S values and biomarkers of source rock organic matter can be used for distinguishing the Cambrian and Upper Ordovician source rocks in the Tarim Basin.     

Enhanced late gas generation potential of petroleum source rocks via recombination reactions: Evidence from the Norwegian North Sea

Gas generation in the deep reaches of sedimentary basins is usually considered to take place via the primary cracking of short alkyl groups from overmature kerogen or the secondary cracking of petroleum. Here, we show that recombination reactions ultimately play the dominant role in controlling the timing of late gas generation in source rocks which contain mixtures of terrigeneous and marine organic matter. These reactions, taking place at low levels of maturation, result in the formation of a thermally stable bitumen, which is the major source of methane at very high maturities. The inferences come from pyrolysis experiments performed on samples of the Draupne Formation (liptinitic Type II kerogen) and Heather Formation (mixed marine-terrigeneous Type III kerogen), both Upper Jurassic source rocks stemming from the Norwegian northern North Sea Viking Graben system. Non-isothermal closed system micro scale sealed vessel (MSSV) pyrolysis, non-isothermal open system pyrolysis and Rock Eval type pyrolysis were performed on the solvent extracted, concentrated kerogens of the two immature samples. The decrease of C₆₊ products in the closed system MSSV pyrolysis provided the basis for the calculation of secondary gas (C_1-5) formation. Subtraction of the calculated secondary gas from the total observed gas yields a “remaining” gas. In the case of the Draupne Formation this is equivalent to primary gas cracked directly from the kerogen, as detected by a comparison with multistep open pyrolysis data. For the Heather Formation the calculated remaining gas formation profile is initially attributable to primary gas but there is a second major gas pulse at very high temperature (>550 °C at 5.0 K min⁻¹) that is not primary. This has been explained by a recondensation process where first formed high molecular weight compounds in the closed system yield a macromolecular material that undergoes secondary cracking at elevated temperatures. The experiments provided the input for determination of kinetic parameters of the different gas generation types, which were used for extrapolations to a linear geological heating rate of 10⁻¹¹ K min⁻¹. Peak generation temperatures for the primary gas generation were found to be higher for Heather Formation (T_max = 190 °C, equivalent to R_o appr. 1.7%) compared to Draupne Formation (T_max = 175 °C, equivalent to appr. R_o 1.3%). Secondary gas peak generation temperatures were calculated to be 220 °C for the Heather Formation and 205 to 215 °C for the Draupne Formation, respectively, with equivalent vitrinite reflectance values (R_o) between 2.4% and 2.0%. The high temperature secondary gas formation from cracking of the recombination residue as detected for the Heather Formation is quantitatively important and is suggested to occur at very high temperatures (T_max approx. 250 °C) for geological heating rates. The prediction of a significant charge of dry gas from the Heather Formation at very high maturity levels has important implications for petroleum exploration in the region, especially to the north of the Viking Graben where Upper Jurassic sediments are sufficiently deep buried to have experienced such a process.     

Oil-source correlation of Lower-Triassic oil seepages in Ni’erguan village,Southern Guizhou Depression,China

There are abundant bitumens and oil seepages stored in vugs in a Lower-Triassic Daye formation (T₁d) marlite in Ni’erguan village in the Southern Guizhou Depression. However, the source of those oil seepages has not been determined to date. Multiple suites of source rocks of different ages exist in the depression. Both the oil seepages and potential source rocks have undergone complicated secondary alterations, which have added to the difficulty of an oil-source correlation. For example, the main source rock, a Lower-Cambrian Niutitang Formation (?₁n) mudstone, is over mature, and other potential source rocks, both from the Permian and the Triassic, are still in the oil window. In addition, the T₁d oil seepages underwent a large amount of biodegradation. To minimize the influence of biodegradation and thermal maturation, special methods were employed in this oil-source correlation study. These methods included catalytic hydropyrolysis, to release covalently bound biomarkers from the over mature kerogen of ?₁n mudstone, sequential extraction, to obtain chloroform bitumen A and chloroform bitumen C from the T₁d marlite, and anhydrous pyrolysis, to release pyrolysates from the kerogen of T₁d marlite. Using the methods above, the biomarkers and n-alkanes released from the oil samples and source rocks were analysed by GC–MS and GC-C-IRMS. The oil-source correlation indicated that the T₁d oil seepage primarily originated from the ?₁n mudstone and was partially mixed with oil generated from the T₁d marlite. Furthermore, the seepage also demonstrated that the above methods were effective for the complicated oil-source correlation in the Southern Guizhou Depression.     

Role of water in hydrocarbon generation from Type-I kerogen in Mahogany oil shale of the Green River Formation

Hydrous and anhydrous closed-system pyrolysis experiments were conducted on a sample of Mahogany oil shale (Eocene Green River Formation) containing Type-I kerogen to determine whether the role of water had the same effect on petroleum generation as reported for Type-II kerogen in the Woodford Shale. The experiments were conducted at 330 and 350 °C for 72 h to determine the effects of water during kerogen decomposition to polar-rich bitumen and subsequent bitumen decomposition to hydrocarbon-rich oil. The results showed that the role of water was more significant in bitumen decomposition to oil at 350 °C than in kerogen decomposition to bitumen at 330 °C. At 350 °C, the hydrous experiment generated 29% more total hydrocarbon product and 33% more C₁₅₊ hydrocarbons than the anhydrous experiment. This is attributed to water dissolved in the bitumen serving as a source of hydrogen to enhance thermal cracking and facilitate the expulsion of immiscible oil. In the absence of water, cross linking is enhanced in the confines of the rock, resulting in formation of pyrobitumen and molecular hydrogen. These differences are also reflected in the color and texture of the recovered rock. Despite confining liquid-water pressure being 7-9 times greater in the hydrous experiments than the confining vapor pressure in the anhydrous experiments, recovered rock from the former had a lighter color and expansion fractures parallel to the bedding fabric of the rock. The absence of these open tensile fractures in the recovered rock from the anhydrous experiments indicates that water promotes net-volume increase reactions like thermal cracking over net-volume decrease reactions like cross linking, which results in pyrobitumen. The results indicate the role of water in hydrocarbon and petroleum formation from Type-I kerogen is significant, as reported for Type-II kerogen.