Coaly Source Rock Research Articles

Preliminary Geochemical Appraisal on Sumatera, Java, and Kalimantan Coaly Source Rocks

In Western Indonesia’s petroleum system, one of the hydrocarbon source rocks was deposited in parallic-deltaic environment with high organic content, categorizing it as coaly source rock. This study focused on geochemical characteristics of 25 coal and coaly shale samples from rock outcrops and well representing the Central Sumatra, South Sumatra, South Central Java, Barito, and Kutai Basin, with additional data from previous studies. TOC analysis and Rock-eval Pyrolysis were carried out to reveal the geochemical characteristics and maturation pathway of the source rock. The TOC analysis results showed a value of 0.5-67.73 wt%, indicating poor-excellent source rock potential. Further rock-eval pirolysis exhibits kerogen type II/II-III (excluding samples from Ngimbang Fm.), with gas-dominated hydrocarbon. Hydrocarbon Index ranging from 4-308 mg/gC indicates possible low-moderate quantity of hydrocarbon that can be generated by the source rocks. Despite the overall fair-good source rock potential, Tmax of the samples indicates a very poor maturity level, with only Upper Talang Akar as the mature candidate. Thus, it can be concluded that young source rock candidates in Western Indonesia (limited to the basins studied in this research) initially possess potential in generating hydrocarbons, if it is not for the immature level of most coaly source rock formations.

Evaluation of Re–Os geochronology and Os isotope fingerprinting of Late Cretaceous terrestrial oils in Taranaki Basin, New Zealand

The rhenium-osmium (Re–Os) isotope system has been applied to several marine and lacustrine petroleum systems worldwide, showing good potential for dating crude oils and correlating them to their source rocks. Here we explore the applicability of the Re–Os geochronometer and Os isotope fingerprinting to terrestrial oils by comparing the Re and Os systematics of Late Cretaceous terrestrial oils from Taranaki Basin, New Zealand, and their correlated coaly source rocks. Comparison is also made with selected Late Cretaceous–Paleocene marine oils and source rocks with varying levels of terrestrial organic matter input.The asphaltene fractions of nine genetically related terrestrial oils from the Maui, Maari-Manaia and Tui Area fields in offshore Taranaki Basin contain low concentrations of Re (0.18–0.45 ppb) and 192Os (1.3–12.7 ppt) comparable to their correlated Late Cretaceous coaly source rocks (Rakopi and North Cape formations; Re 0.19–0.37 ppb, 192Os 5.3–9.6 ppt). The Re and 192Os concentrations in these terrestrial oils are generally one to two orders of magnitude lower than those in marine-sourced oils from the Kora Field in offshore Taranaki Basin and surface seeps in East Coast Basin.The 187Re/188Os and 187Os/188Os ratios of the terrestrial oils failed to yield a precise Re–Os isochron age. We attribute this to: (1) insufficient homogenisation of oils with widely variable initial 187Os/188Os (Osi) values inherited from thick, coaly source rock intervals (up to about 2700 m) within the Maui sub-basin and northern Kahurangi Trough kitchens; (2) insufficient spread of 187Re/188Os values (only 275 units); (3) insufficient time since oil expulsion (modelled to be from approximately 10 Ma to the present day) for the evolution of an isochron; and (4) possible effects of water washing of the oil columns. Although all of the studied oils are water-washed to varying degrees, there is no definitive evidence that water washing has disturbed the Re–Os systematics.The Osi values for the studied terrestrial oils inherited at the modelled time of oil expulsion (approximately 10 Ma) display a wide range (0.47–1.14) and do not provide a unique fingerprint of their Late Cretaceous coaly source rock formations. Osmium isotope compositions therefore appear to have limited potential for broad oil-source rock correlation within the predominantly coal-sourced petroleum systems of Taranaki Basin. The Osi values may, however, provide useful distinction of the terrestrial oils emanating from the Kahurangi Trough (Tui Area oils) from those of the Maui sub-basin (Maui and Maari-Manaia oils) based on the significantly more radiogenic values of the Tui Area oils (0.84–1.14 compared with 0.47–0.65 from Maui and Maari-Manaia oils). Overall, this study has provided useful insights into the potential application of the Re–Os isotope system to terrestrial, coal-sourced petroleum systems.

Carboniferous–Permian Coaly Source Rock Formation in North China: Implications from Geochemical Characteristics and Depositional Environments

Carboniferous–Permian Coaly Source Rock Formation in North China: Implications from Geochemical Characteristics and Depositional Environments

Delineation of coaly source rock distribution and prediction of organic richness from integrated analysis of seismic and well data

Coaly facies (coals, shaly coals and coaly mudstones) are the primary source rock in several important petroleum basins in SE Asia and Australasia. Delineating these facies and quantifying their organic richness within kitchen areas are some of the key risks for petroleum exploration. To improve their delineation and characterisation using seismic data, a case study was undertaken of the coal-bearing Paleocene and Eocene intervals within the Maari 3D seismic volume area, offshore southern Taranaki Basin, New Zealand. Supporting data were acquired from well logs (including borehole image logs), existing geochemical analyses of well cuttings, and new laboratory measurements of in-situ geophysical and geochemical properties of coal samples from onshore coal mines and other outcrops. In the Paleocene–Eocene interval in the Maari 3D, coaly facies display characteristic low density (<2.5 g/cc) and velocity (<4000 m/s) and appear as bright, resistive layers in image logs. To delineate these facies in the Maari 3D volume, a post-stack seismic inversion was carried out and a P-impedance (product of density and P-wave velocity) model was prepared. Coaly facies exhibit moderate–high amplitude and moderately continuous (up to ~5 km) seismic reflectors, with low P-impedance (<9000 m/s × g/cc) character. Interval P-impedance and amplitude maps reveal temporal variation in the distribution and abundance of coaly facies within the Paleocene–Eocene coastal plain depositional environment. A logarithmic relationship between P-impedance and TOC was used to convert average P-impedance maps to proxy TOC maps for five Paleocene–Eocene time intervals. Coaly facies are most abundant in the low P-impedance areas in the southwestern and central parts of the study area where average TOC is estimated up to 30 wt.%. P-impedance-derived estimates of TOC may be less reliable in structurally high areas hosting hydrocarbon-bearing sandstones and siltstones as some of these facies show similar P-impedance character to coaly facies.

HIGHER LANDPLANT –DERIVED BIOMARKERS IN LIGHT OILS AND CONDENSATES FROM THE COAL‐BEARING EOCENE PINGHU FORMATION, XIHU SAG, EAST CHINA SEA SHELF BASIN

The Cenozoic Xihu Sag in the East China Sea Shelf Basin contains large reserves of coals together with liquid petroleum derived from coal‐associated sediments. However, the origin of the petroleum is not well understood. In this study, biomarker assemblages in a suite of recently discovered light oils and condensates from the Paleogene succession in the western margin of in the Xihu Sag were investigated using gas chromatography – mass spectrometry. The objectives were to investigate the samples' thermal maturity and the depositional environment of the precursor source rocks which generated the oils. The light oils are believed to have been derived from coaly source rocks in the Eocene Pinghu Formation.Assessment of thermal maturity based on CPI, pristane/n‐C17 ratio and isomerisation ratios of C29 steranes and C31 homohopanes suggest that the hydrocarbons have a relatively low maturity in the early to mid oil generation window. The distribution of isoprenoids relative to n‐alkanes, the high pristane/phytane ratios (5.1–10.7), the almost complete absence of gammacerane and C33+ homohopanes, and the low dibenzothiophene/phenanthrene ratios indicate that the source rocks of the hydrocarbons were deposited in a relatively oxic and sulphate‐poor fluvio‐deltaic environment which was favourable for coal measure development.Abnormally abundant gymnosperm‐derived diterpanes including labdane, 19‐norisopimarane, fichtelite, rimuane, pimarane, isopimarane, 17‐nortetracyclic diterpene, phyllocladanes and abietane were detected in the samples analysed. 16a(H)‐Phyllocladane was identified unambiguously and kauranes were confirmed to be absent. In addition, three 19‐norisopimarane isomers, 13β(H)‐atisane, and 20‐normethylatisane were tentatively identified in the studied samples. The distributions of n‐alkanes, isoprenoids and regular steranes, the presence of 4β(H)‐eudesmane and oleanane, high Pr/Ph ratios and the abundant diterpanes together suggest that the hydrocarbons were derived from a coaly source rock. Gymnosperms of the conifer families Cupressaceae (especially the former Taxodiaceae) and Pinaceae are interpreted to be the major source of the diterpanes and to have made a significant contribution to the coaly source rock. However, the low abundance of oleanane relative to diterpanes may underestimate the contribution from angiosperms relative to gymnosperms. This could be due to differential preservation and alteration of the di‐ and triterpenoid precursors during diagenesis and the occurrence of non‐specific precursors in higher land plants.

Carbon and Hydrogen Isotopic Reversals in Highly Mature Coal-Derived Gases: A Case Study of Paleozoic Gases in the Southern Ordos Basin, China

The compositional carbon isotopic seriesδ13C-CH4&lt;δ13C-C2H6&lt;δ13C-C3H8&lt;δ13C-C4H10is common in thermogenic gases. With the exploration of deeper strata, however, isotopic reversals (δ13C-CH4&gt;δ13C-C2H6&gt;δ13C-C3H8) in overmature unconventional shale gases and conventional (coal-derived) gases have been identified. Paleozoic gases in the southern Ordos Basin, China, with partial or complete isotopic reversals, were studied as examples of isotopic fractionation in overmature coal-derived gases. Isotopic compositions of gases of different maturities from the Ordos Basin and shale gases from around the world were compared. Results indicate that carbon isotopic series are related to maturity. Complete isotopic reversal occurs mostly in regions with vitrinite reflectanceRo&gt;2.4%. Where2.4%&gt;Ro&gt;2.0%, almost all gases display partial isotopic reversal, withδ13C-CH4&gt;δ13C-C2H6orδ13C-C2H6&gt;δ13C-C3H8. Carbon isotopic reversal in coal-derived gases is not caused by abiotic origin, the mixing of gases from different types of source rock, abiotic polymerization, wet gas cracking, and other mechanisms that contribute to reversal in shale gases. Based on the unique structure of coaly source rock and the geology of the Ordos Basin, closed-system aromatization-polycondensation reactions are considered the most likely cause of carbon isotopic reversal. During the reactions, isotopically light gases are generated by recombination of previously formed hydrocarbons and residual kerogen-coal. Hydrogen isotopic reversal in the southern Ordos Basin might also be caused by aromatization-polycondensation reactions.

A REVIEW OF THE COALY SOURCE ROCKS AND GENERATED PETROLEUMS IN THE DANISH NORTH SEA: AN UNDEREXPLORED MIDDLE JURASSIC PETROLEUM SYSTEM?

This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&amp;P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (&gt;150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up to the present day. High Middle Jurassic reservoir temperatures prevent biodegradation.

Lower Paleozoic source rocks and natural gas origins in Ordos Basin, NW China

Abstract Based on the geochemical characteristics of Lower Paleozoic gases from 154 most recently drilled wells and their genetic type, in combination with the organic abundance evaluation of 733 core samples from the Lower Paleozoic, the origin of Lower Paleozoic gases in Ordos Basin was discussed. According to the carbon isotope data of paraffin gases in the gas samples and the geological background, the Lower Paleozoic gases are divided into three types and four sub-types: (1) the coal-derived gas generated from the Upper Paleozoic coaly source rock; (2) the oil-associated gas sourced from the Lower Paleozoic source rock, and (3) the mixing gas originated from the Upper Paleozoic coaly source rock and Paleozoic limestone, and the mixing gas can be divided into two sub-types, the mixing gas of positive carbon isotopic series and that of negative carbon isotopic series. From the TOC and organic maceral results of Lower Paleozoic source rock, the samples below salt have an average TOC of 0.3%, with 28.2% of them having TOC>0.4%, the kerogen type being sapropel type, showing great gas generating potential. The Lower Paleozoic gases are primarily coal-derived gas generated from the Upper Paleozoic coal, some oil-associated gas of self-source and self-reservoir can be found in pre-salt reservoirs in the central-eastern basin, where the developed source rock can serve as the source of some Lower Paleozoic gas.

Next steps to crack the code on tight Permian Toolachee and Patchawarra sandstones of the Cooper Basin, southwest Queensland

Historic wells drilled by Real Energy Corporation Limited (Real Energy) in the Windorah Trough (Cooper Basin, southwest Queensland) characterised the Toolachee and Patchawarra formations as being gas-charged, tight-gas, sandstone/lacustrine shale sequences having layers of coaly source rock with high total organic content and moderate hydrocarbon indices. Consistent with being tight-gas reservoirs, drill stem tests have mostly either failed to produce gas or resulted in non-commercial flow rates. To date, North American methodologies for tight and shale gas extraction have not been consistently successful when applied in non-normal stress regimes outside of North America (i.e. Cooper Basin, China, Poland, Middle East, etc). Real Energy anticipated that North American technologies and practices were not likely to be directly applicable, as noted by published case studies for Australian shale gas wells (Johnson and Greenstreet, 2003; Pitkin et al, 2012; Scott et al, 2013; Johnson et al, 2015). Thus, it became an imperative to evaluate any methodologies or technologies more applicable for the Australian strike-slip to transpressional stress regimes to prevent fracture misalignment or disorientation, effects that result in ineffective fracture stimulation. Overall, a more scientific approach must be applied to developing and understanding the most efficient reservoir stimulation processes (e.g. drilling techniques, rock mechanical properties determination, well azimuth, perforating schema, and well interval selection) to optimise the stimulated reservoir volume (SRV). In this extended abstract the authors take the first steps at defining the stimulation strategies required for these tight sandstones using data and results from two case study wells. The authors outline the well observations and report key lessons in a cooperative spirit to solicit industry feedback and further technologies that can aid development of fit-for-purpose technologies to facilitate extraction of these largely untapped resources across the undeveloped troughs and flanks of the Cooper Basin.

Marine influence helps preserve the oil potential of coaly source rocks: Eocene Mangahewa Formation, Taranaki Basin, New Zealand

Many Cretaceous–Cenozoic coaly source rocks in Australasian and southeast Asian basins were deposited in coastal plain environments, yet the effect of early diagenetic marine influence on their oil potential is not well understood. An integrated organic geochemical and petrographic study of humic coals from the Eocene Mangahewa Formation (Taranaki Basin, New Zealand) was undertaken with coals predominantly from raised mire petrofacies, with subordinate proportions from planar mires. The total S content of 0.63–4.4% (dry, ash-free) indicated very slight to strong degrees of marine influence. Other than minor addition of inferred mangrove derived suberinite and associated liptodetrinite, the degree of marine influence had no obvious effect on maceral or plant tissue abundance. However, hydrogen index (HI) values were up to ca. 150% (109mgHC/gTOC) higher, and total (C6+) oil potential up to ca. 140% (43mg/gTOC) higher among the more strongly marine influenced coals. Correlation of organic S with solvent extract parameters pristane/phytane, C27–C29 diasteranes/steranes, C29 steranes/hopanes, C35/(C35+C34) homohopanes and oleanane index suggested that inundation of brackish water into the early diagenetic peat forming environment enhanced the bio-resistance of higher plant and other lipids through sulfurization, thereby helping to preserve more of the inherent H content and total oil potential of the original peat biomass. Conversely, marine influence had only a minor effect on the capacity of Mangahewa coals to generate paraffinic oil. Total (n-C6+) and non-volatile (n-C15+) paraffinic oil potentials were instead controlled primarily by the abundance of leaf derived cutinite and associated liptodetrinite. This, in turn, was dependent on the type of peat mire facies, with planar mire facies having better potential for preservation of leaf litter than raised mire facies because of their generally higher groundwater level. Marine influence is nonetheless beneficial for paraffinic oil charge from coaly source rock sequences in that the associated higher HIs enhance the efficiency and quantum of paraffinic oil expulsion through increased saturation of the coal pore system.

OIL‐PRONE LOWER CARBONIFEROUS COALS IN THE NORWEGIAN BARENTS SEA: IMPLICATIONS FOR A PALAEOZOIC PETROLEUM SYSTEM

In this study, we assess the oil generation potential of Lower Carboniferous, liptinite‐rich coals in the Tettegras Formation on the Finnmark Platform, southern Norwegian Barents Sea. Oil from these coals has been expelled into intercalated sandstones. The coals may have contributed to petroleum recorded in well 7128/4–1 on the Finnmark Platform and may constitute a new Palaeozoic source rock in the Barents Sea.The Tettegras Formation coals contain up to 80 vol.% liptinite (mineral matter free base) and have low oxygen indices. Hydrogen indices up to 367 mg HC/g TOC indicate liquid hydrocarbon potential. In wells 7128/4–1 and 7128/6–1, the coals have vitrinite reflectance Ro= 0.75–0.85 %. Compared to shale and carbonate source rocks, expulsion from coal in general begins at higher maturities (Ro= 0.8–0.9% and Tmax= 444–453°C). Thus, the coals in the wells are mostly immature with regard to oil expulsion. The oil in well 7128/4–1 most likely originates from a more mature part of the Tettegras Formation in the deeper northern part of the Finnmark Platform. Wide variations in biomarker facies parameters and δ13C isotope values indicate a heterogeneous paralic depositional setting. The preferential retention by coal strata of naphthenes (e.g. terpanes and steranes) and aromatic compounds, compared to n‐alkanes and acyclic isoprenoids, results in a terrigenous and waxy oil. This oil however contains marine biomarkers derived from the intercalated shales and siltstones. It is therefore important to consider the entire coal‐bearing sequence, including the intercalated shales, in terms of source rock potential.Coals of similar age occur on Svalbard and Bjørnøya. The results of this study therefore suggest that a Lower Carboniferous coaly source rock may extend over large areas of the Norwegian Barents Sea. This source rock is mature in areas where the otherwise prolific Upper Jurassic marine shales are either immature or missing and may constitute a new Palaeozoic coal‐sourced petroleum system in the Barents Sea.

Distribution and fractionation mechanism of stable carbon isotope of coalbed methane

The stable carbon isotope values of coalbed methane range widely, and also are generally lighter than that of gases in normal coal-formed gas fields with similar coal rank. There exists strong carbon isotope fractionation in coalbed methane and it makes the carbon isotope value lighter. The correlation between the carbon isotope value and R o in coalbed methane is less obvious. The coaly source rock maturity cannot be judged by coalbed methane carbon isotope value. The carbon isotopes of coalbed methane become lighter in much different degree due to the hydrodynamics. The stronger the hydrodynamics is, the lighter the CBM carbon isotopic value becomes. Many previous investigations indicated that the desorption-diffusion effects make the carbon isotope value of coalbed methane lighter. However, the explanation has encountered many problems. The authors of this article suggest that the flowing groundwater dissolution to free methane in coal seams and the free methane exchange with absorbed one is the carbon isotope fractionation mechanism in coalbed methane. The flowing groundwater in coal can easily take more 13CH4 away from free gas and comparatively leave more 12CH4. This will make 12CH4 density in free gas comparatively higher than that in absorbed gas. The remaining 12CH4 in free gas then exchanges with the adsorbed methane in coal matrix. Some absorbed 13CH4 can be replaced and become free gas. Some free 12CH4 can be absorbed again into coal matrix and become absorbed gas. Part of the newly replaced 13CH4 in free gas will also be taken away by water, leaving preferentially more 12CH4. The remaining 12CH4 in free gas will exchange again with adsorbed methane in the coal matrix. These processes occur all the time. Through accumulative effect, the 12CH4 will be greatly concentrated in coal. Thus, the stable carbon isotope of coalbed methane becomes dramatically lighter. Through simulation experiment on water-dissolved methane, it had been proved that the flowing water could fractionate the carbon isotope of methane, and easily take heavy carbon isotope away through dissolution.

DISTRIBUTION OF SOURCE ROCKS AND MATURITY MODELLING IN THE NORTHERN CENOZOIC SONG HONG BASIN (GULF OF TONKIN), VIETNAM

The northern offshore part of the Cenozoic Song Hong Basin in the Gulf of Tonkin (East Vietnam Sea) is at an early stage of exploration with only a few wells drilled. Oil to source rock correlation indicates that coals are responsible for the sub‐commercial oil and gas accumulations in sandstones in two of the four wells which have been drilled on faulted anticlines and flower structures. The wells are located in a narrow, structurally inverted zone with a thick predominantly deltaic Miocene succession between the Song Chay and Vinh Ninh/Song Lo fault zones. These faults are splays belonging to the offshore extension of the Red River Fault Zone.Access to a database of 3,500 km of 2D seismic data has allowed a detailed and consistent break‐down of the geological record of the northern part of the basin into chronostratigraphic events which were used as inputs to model the hydrocarbon generation history. In addition, seismic facies mapping, using the internal reflection characteristics of selected seismic sequences, has been applied to predict the lateral distribution of source rock intervals. The results based on Yükler ID basin modelling are presented as profiles and maturity maps. The robustness of the results are analysed by testing different heat flow scenarios and by transfer of the model concept to IES Petromod software to obtain a more acceptable temperature history reconstruction using the Easy%R0 algorithm.Miocene coals in the wells located in the inverted zone between the fault splays are present in separate intervals. Seismic facies analysis suggests that the upper interval is of limited areal extent. The lower interval, of more widespread occurrence, is presently in the oil and condensate generating zones in deep synclines between inversion ridges. The Yükler modelling indicates, however, that the coaly source rock interval entered the main window prior to formation of traps as a result of Late Miocene inversion.Lacustrine mudstones, similar to the highly oil‐prone Oligocene mudstones and coals which are exposed in the Dong Ho area at the northern margin of the Song Hong Basin and on Bach Long Vi Island in Gulf of Tonkin, are interpreted to be preserved in a system of undrilled NW–SE Paleogene half‐grabens NE of the Song Lo Fault Zone. This is based on the presence of intervals with distinct, continuous, high reflection seismic amplitudes. Considerable overlap exists between the shale‐prone seismic facies and the modelled extent of the present‐day oil and condensate generating zones, suggesting that active source kitchens also exist in this part of the basin. Recently reported oil in a well located onshore (BIO‐STB‐IX) at the margin of the basin, which is sourced mainly from “Dong Ho type” lacustrine mudstones supports the presence of an additional Paleogene sourced petroleum system.

Guidelines for assessing the petroleum potential of coaly source rocks using Rock-Eval pyrolysis

Coaly source rocks are sufficiently different from marine and lacustrine source rocks in their organic matter characteristics to warrant separate guidelines for their assessment using Rock-Eval pyrolysis. The rank threshold for oil generation is indicated by the increase in BI (S1/TOC) at Rank(Sr)∼9–10 (Tmax ∼420–430 °C, Ro ∼0.55–0.6%), and the threshold for oil expulsion is indicated by the peak in QI ([S1+S2]/TOC) at Rank(Sr)∼11–12.5 (Tmax ∼430–440 °C, Ro ∼0.65–0.85%). The pronounced rank-related increase in HI (S2/TOC) prior to oil expulsion renders the use of immature samples inappropriate for source rock characterisation. A more realistic indication of the petroleum generative potential and oil expulsion efficiency of coaly source rocks can be gained from samples near the onset of expulsion. Alternatively, effective HI′ values (i.e. HIs near the onset of expulsion) can be estimated by translating the measured HIs of immature samples along the maturation pathway defined by the New Zealand (or other defined) Coal Band. Coaly source rocks comprise a continuum of coaly lithologies, including coals, shaly coals and coaly mudstones. Determination of the total genetic potential of coaly source rock sequences is best made using lithology-based samples near the onset of expulsion.

Depositional environments and oil potential of Jurassic/Cretaceous source rocks within the Seychelles microcontinent

The Seychelles microcontinent became isolated between the Somali, Mascarene and Arabian basins of the Indian Ocean as a result of the Mesozoic fragmentation of Gondwana. Major rifting events occurred during the Triassic-Middle Jurassic and Late Cretaceous (Cenomanian-Santonian and Maastrichtian) during which shaly source rock facies accumulated in principally marginal marine:deltaic environments. Between these times, post-rift passive margin deposition De Wit et al., 1988hin restricted to open marine environments produced shaly source rocks during late Middle Jurassic-Early Cretaceous, Campanian-Maastrichtian and Paleocene times. Recent geochemical analysis of cuttings from the Seagull Shoals-l well has identified an oil-prone liptinitic (Type II) coaly shale De Wit et al., 1988hin early Middle Jurassic abandoned deltaic deposits. This coaly source rock is regionally developed, having also been identified in the Majunga and Morondava basins of Madagascar. Oil-prone Type II organic matter has also been identified in the Owen Bank A-1 well De Wit et al., 1988hin restricted marine shales of late Middle Jurassic age. These shales are part of a thick post-rift source rock sequence that extends into the Early Cretaeous and is in part correlative De Wit et al., 1988h the proven Late Jurassic Uarandab Shale of Somalia. Analysis of Campanian marine shales from Reith Bank-1 well identified significant dilution of total organic carbon content in composite, compared to picked, well cuttings samples. This finding supports a published inference that these post-rift shales have source rock potential. The very limited drilling of the various Jurassic:Cretaceous source rock sequences in Seychelles (only three penetrations, all De Wit et al., 1988hin a 13 km radius) indicates that they span the entire maturity window and that some have generated hydrocarbons. However, the petroleum system associated De Wit et al., 1988h the Triassic-Early Cretaceous rift:drift sequence has been tested only by three invalid wells at the western extremity of the Seychelles Plateau, whilst that associated De Wit et al., 1988h the Late Cretaceous rift:drift sequence remains untested. ©1998 Elsevier Science Ltd. All rights reserved.

Maturation effects on absolute biomarker concentration in a suite of coals and associated vitrinite concentrates

Extensive bulk chemical and petrographic characterization of 37 coals and vitrinite concentrates of the Lower Kittanning seam (Carboniferous) from western Pennsylvania and eastern Ohio shows that the coals are compositionally similar and represent a uniform organic facies. Geochemical differences among the samples are due to rank, with vitrinite reflectances ranging from 0.53 to 1.76%. The sample suite affords an excellent opportunity to evaluate the effects of coal rank on a range of commonly used molecular indicators of thermal maturity. Absolute concentrations of molecular constituents, rather than peak ratios, were determined based on addition of internal standards (5β cholane and d 10-anthracene) to the extractable organic matter prior to separation by liquid chromatography. Absolute concentrations of C 29 ααα 20 R and 20 S sterane isomers provide clues to the processes involved in the apparent “sterane epimerization” reaction. The 20 R isomer is initially present in the free state in much higher concentrations than the 20 S isomer. With increasing thermal evolution of the kerogen, both isomers are liberated from the kerogen with increasing proportionality of 20 S, resulting in a net increase in 20S (20R + 20S) ratio. There appears to be little evidence for epimerization of molecules in the free state. Kinetic modeling of sterane epimer evolution therefore requires a more elaborate reaction scheme involving both formative and degradative reactions, as opposed to a simple A-to-B conversion. The amount of 1-MDBT remains constant over a wide maturity range, signifying equal rates of formation and destruction of this compound relative to the total EOM. The amount of 4-MDBT shows a general increase with maturity, the most pronounced change occurring at maturities above about 1.3% R m. The ratio of 4 1 MDBT (“MDR parameter”) therefore appears to be particularly useful for maturity assessment at elevated levels (e.g. light oil/condensate range). Some source-dependent molecular parameters, such as pristane/phytane, C 27 C 29 sterane, 4β(H)-eudesmane/8β(H)-drimane and C 30 hopane C 23 cheilanthane , were found to change as a function of coal rank. The most pronounced changes occur at higher levels of maturity ( R m > 1.1%), where these molecular source indicators take on a more “marine” or “deep-water lacustrine” signature, even though there is no change in depositional environment of the coaly facies. At lower levels of maturity corresponding to the typical oil window, the changes are less pronounced, but may still affect attempts to correlate a crude oil with an immature sample of its suspected coaly source rock. The maturity dependence of these “source” parameters should be taken into account in petroleum geochemical studies involving non-marine coaly systems.

Reaction of Organic Material to Progressive Geologic Heating: ABSTRACT

The generation of oil is a process that begins to occur at some point during the burial history of a source rock. This onset of maturation is dictated largely by temperature and residence time. However, the nature of the source rock itself also influences the hydrocarbon product being expelled from the source rock. The vast majority of the world's oil can be ascribed to source rocks of the following types. (1) Marine mudrocks deposited in anoxic conditions and dominated by phytoplankton organisms; this type of source rock can have a carbonate or clay inorganic matrix and total organic carbon values from 1 to 30% (commonly 4 to 10% when immature). Examples of this classical oil source rock would be the source rocks of western Canada, the Middle East, and the North Sea. ( ) Specific coal facies such as torbanites and cannel coals, which contain a mixture of hydrogen-rich plant detritus (e.g., spores, pollen, cuticle, resin, and algae); deposition was probably in open-water areas of an overall coal-swamp environment. Examples of hydrocarbons from this type of source include the Gippsland basin, Canadian Beaufort Sea, and Southeast Asia. (3) Lacustrine organic-rich deposits, rich in freshwater algae, which ultimately result in high-wax crude oils. Examples are relatively rare, but include major source rocks in the Uinta basin and China. The effect of increasing maturity on marine mudrocks of the Devonian Duvernay Formation of Alberta illustrates oil generation from this type of source rock. The data base in this unit consists of 40 conventional cores, ranging from immature to completely overmature, and 80 oils from separate accumulations sourced from the Duvernay. An illustration of oil generation in a coaly source rock is provided by a single core from the Lower Cretaceous of the Beaufort-Mackenzie basin plus many of the oils and condensates reservoired in that area. End_of_Article - Last_Page 247------------