South West Sulawesi Field Trip, 1991

Geochemistry of three carbonaceous sediments CJMD 1991

Carbonaceous sediments From South Sulawesi (IPA field Trip 1991) I Summary A brief investigation of three different Eocene carbonaceous outcrop deposits from South Sulawesi revealed all Formations to be very immature relative the to the oil window. The three samples exhibited different palaeoenvironments of deposition: marine (containing drifted log fragments); Marine/sub aerial (perhaps a temporarily vegetated island) and: terrestrial. The Eocene Tonasa and Malawa formations sampled in southern Sulawesi are immature relative to the oil window and show no potential to generate oil and little or no potential to generate gas. II Introduction Four localities were visited where Tertiary carbonaceous sediments were known to outcrop. Three “coal” outcrop samples were selected from these Eocene deposits for geochemical evaluation. Bulk, optical and molecular geochemistry was used to establish the organic richness of the coals, their maturity and further detail concerning the depositional Palaeoenvironment. One particularly interesting coal sample was collected from an inter-bed in an otherwise largely uninterrupted 300m+ carbonate sequence of Eocene age (Tonasa Limestone). III The Samples

1. Sample code: Sula1 Location: Under sill/waterfall near track to Balangnaru

This sample was collected from interbedded siltstones, claystones and sandstones of the Eocene Malawa Formation, 5M below a thick pyroxene basalt sill. The sill is thought to have had little or no thermal effect on the samples due the degree of separation involved. The sample was taken from a pyritous partially carbonised log.

2. Sample code: Sula2 Location: Upper most reached of the Balangbaru River

This “coal” was collected form a 6 cm think carbonaceous interbed within the Upper Eocene Tonasa Limestone. This sample was interesting as there appeared to be no graduation of facies between the massive Tonasa Limestone facies and the carbonaceous layer. The possibility that this represents a brief period of plant colonization of a temporary carbonate shoal was mooted, the possibility that the carbonaceous deposit was some kind of algal build up was also investigated.

3. Sample code: Sula 3 Location: 1km north west of Balangbaru village (on the same height

contour as Sula 2) Carbargillite/coal from a thick carbonaceous horizon within the Lower Eocene, Malawa Formation. The sample was originally described as a carbargillite, as in hand specimen it appeared to have a both high carbonaceous and argillaceous content. The sample displayed evidence of slickensliding, and this was though to be due to recent slumping/soil creep. IV Analytical programme The samples were analysed under reflected light microscopy, by UV light excitation microscopy, Leco TOC determination, Rock Eval Pyrolysis, Gas Chromatography and Gas Chromatography-Mass Spectrometry (Selected Ion Mode only). V Discussion Sample 1: Balangbaru, woody fragment Amount of organic matter: This sample contained 47% organic carbon. This is consistent with the sample type. Type of organic matter and Palaeoenvironment of deposition: The organic matter consists of vitrinitic and inertintic material. The wood fragment was partially pyritised and persevered in a marine clay. It is thought the log floated out to sea, became waterlogged, sank, and was subsequently preserved in the fine grained argillaceous sediments. Anaerobic conditions within the sediment allowed the formation of framboidal pyrite. Maturity The formation containing the samples is very immature relative to the oil widow. A value of 0.28% was recorded. Whilst Ro% determinations can be unreliable at such low levels of maturity all other indications confirm this extremely low level of maturity (see also classic immature GC profile). Heat from the sill did not affect the sample. No potential for oil or gas generation is indicated. Sample 2: Balangbaru River, “coaly interbed” Amount of organic matter: A value of 4.65% TOC was recorded for this sample. It would be better to describe this horizon as carbonaceous at best.

Type of organic matter and Palaeoenvironment of deposition: Pyrolysis data indicates that all the carbonaceous material is completely inert. An HI value of just 6 suggests that the organic matter is almost all carbon. No recognisable plant remains or structured material of any description was found during optical analysis. It is believed this horizon represents a period of time when the Tonasa Limestone sea was very shallow and from time to time the sediment interface was exposed to the atmosphere. It is envisaged that a substantial plant community built up in the vicinity, then was submerged and broken up by waves. The plant material then being thoroughly comminuted, disseminated over a wide area, and in the process was thoroughly oxidised. The possibility of this horizon being the result of some kind of algal build up. An algal mat or microbial build up is dismissed as such organic matter is usually relatively resilient. There is also no molecular or bulk geochemical signature to support this possibility Maturity: This horizon is immature relative to the oil window. A value of Ro 0.33% was recorded. Again this value is thought to be wholly representative despite the limitations of Ro% at low levels of maturity (see also immature GC and GCMS and MPI data). This carbonaceous layer has no potential what-so-ever to generate hydrocarbons. This sample contained 6% TOC. This value is extremely low for what was originally described as a coal, then later as a carbargillite. Sample 3. NW of Balangbaru, carbargillite Amount of Organic matter: This sample contained 6% TOC. This value is extremely low for what was originally described as a coal, then later as a carbargillite. This horizon can at best be described as a carbonaceous; it is certainly not a coal or even a carbargillite. Coal is however mined in the area. Type of organic matter and Palaeoenvironment of deposition HI values are modest and aliphatic hydrocarbons are abundant. Few isoprenoids are present in the samples. The low levels of Pristane and Phytane is perhaps surprising. The slightly greater abundance of Pristane is perhaps indicative of slightly oxic conditions. A strong odd over even n-Alkane presence may be seen in the GC profile in the higher homologues.

Hopene/hopanoidal triterpanes are in far greater abundance than the sterenes/steroidal hydrocarbon. A triterpane signature can even be seen in the GC trace. Methyl sterenes/steroidal hydrocarbons, both the aromatic and aliphatic homologies are also abundant. The envisaged environment of deposition is terrestrial, one in which large quantities higher plant material accumulated and was thoroughly reworked by bacteria; such an environment could include a raised peat swamp facies. Maturity It was not possible tie determine the maturity of this sample using Vitrinite reflectance. However GC and GCMS profiles contain hydrocarbon distributions which are clearly immature relative to the oil window. VI Acknowledgements LEMIGAS Karamjaya Mass Spectrometry Marnida Ulibasa Chromatography Widiarto Optical Petrology Sutiania & Yuwono Preparative geochemistry

APPENDICES

SOUTH WEST SULAWESI FIELD TRIP Gas chromatography, aliphatic hydrocarbons

SOUTH WEST SULAWESI FILED TRIP Gas chromatography – mass spectrometry 1 Aliphatic hydrocarbon distribution II Aromatic hydrocarbon distribution Selected ion recording mode (SIM) Layout: 1: Reference sample 2: Sula 2, carbonaceous interbed 3: Sula 3, carbonaceous shale

I ALIPHATIC HYDROCARBONS

II AROMATIC HDORCARBONS

ANALYTCIACL & INTERPRETATIVE METHODS

Analytical techniques and interpretation This appendix describes the basic analytical techniques and interpretative methods used in petroleum exploration geochemistry. 1 Sample preparation 1.1 Introduction Samples are received by geochemical laboratories in the form of canned well-site cuttings, bagged cuttings, cores, outcrop samples, gases and oils. Each sample is examined visually and described; contaminants such a drilling mud additives and caved material are removed. The drilling muds are removed with cold water, unless they are oil based (not ideal): then the samples are washed in dichloromethane. Once dried the rock samples are divided for optical and molecular analysis. The optical fraction is ground to 1mm and the fraction fro molecular analysis ground to <212µm. Condensates and crude oils are separated into fractions by liquid chromatography or diluted as appropriate prior to analysis. Headspace gases and other gas samples are analysed directly. 1.2 Kerogen preparation Samples requiring kerogen analysis are finely ground as for optical analysis, treated with excess hydrochloric acid (HCl) to remove the carbonates and finally treated with excess heated hydrofluoric acid (HF) to remove any silicates. The kerogen is then washed and dried and mounted on a glass slide for viewing in transmitted light for Spore Colouration (SC) and kerogen type analysis. 1.3 Solvent extraction Approximately 100 grams of finely ground rock (<212µm) is refluxed in a Soxhlet apparatus for 18 hours with an azeotropic mixture of dichloromethane /methanol (93:7). Any elemental sulphur is removed with activated copper turnings. The solvent and extract are then decanted reduced to dryness by means of a rotary evaporator. The total weight of the extracts (TSE) is then recorded. The separation from the TSE of the aliphatic and aromatic fractions is achieved by liquid column chromatography (LLC) or thin layer chromatography (TLC) depending on how much sample material is required. Liquid chromatography provides sufficient sample material for several analyses. The oil or extract sample is dried onto deactivated alumina and placed on an alumina:silica column (1.3). The aliphatic hydrocarbon fraction is firstly eluted with a pentane and 10% dichloromethane mixture. The resulting fractions are stored for further analysis. When less sample material is needed TLC is used to separate the aliphatic from the aromatic hydrocarbons. Pre prepared silica gel plates are first conditioned, spotted with oil or extract material and then developed in hexane. An accurate percentage breakdown of the oil or extract into saturate and aromatic hydrocarbons, resinous compounds and asphaltenic compounds (SARA) is achieved by the Iatroscan method. The Iatroscan method uses automated combined TLC with a flame ionisation detector (TLC/FID).

The asphaltenes may be collected by precipitation overnight in Hexane. The precipitate is filtered off, dried, weighed and stored for analysis. 2. Maturity evaluation Optical microscopy is the main technique used for maturity estimation in sediments. Three techniques are used at LEMIGAS: Vitrinite Reflectance (Ro%), Spore Fluorescence (SF) and spore colouration (SC). Further maturity evaluation techniques used include: Rock Eval Pyrolysis Tmax determination; in both source rock extracts and oils, maturity is determined by examining the n-Alkane distributions, the biomarkers and the aromatic hydrocarbon ratios by gas chromatography (GC) and gas chromatography –mass spectrometry (GCMS). 2.1 Vitrinite Reflectance The whole rock technique is preferred; however when there is insufficient suitable material on which to make measurements isolated kerogen mounts are also examined reflected light. The crushed samples is mounted in a liquid polystyrene resin, allowed to harden, ground on successively finer carborundum paper, and then polished with successively finer alumina powders. The samples are then viewed under reflected light. The samples are then viewed under reflected light using a Leitz (normally) photometric microscope with reference to optical standards. The standards are viewed in white light using oil immersion objectives and a green filter with a peak transmission of 546nm. The immersion oil has a refractive index (Nt) of 1.518 at 23ºC. The values are recorded as a percentage of light reflected. Changes in reflectance values greater than Ro 0.1% are thought to be significant. The standards used are usually: Yttrium aluminium garnet (YAG) Ro% 0.921 and artificial sapphire Ro 0.504%. Considerable operator skill is required to distinguish between autochthonous and allochthonous vitrinitic components. Other features such as degree of bitumen staining, mineralogy, micropalaeontology and oxidation effects are also noted. Values of Vitrinite reflectance with reference to the oil and gas windows may be seen in figure entitled “correlation table, molecular parameters”. (Fig A1). Reflectance measurements are particularly reliable above Ro 0.5% below this value other parameters are best used. In immature rocks, the reflectance changes erratically with increasing maturity. In lithologies subjected to rapid subsidence, in zones of oil ingress and in horizons of intense reworking Vitrinite reflectance values may well be unreliable or even unavailable. 2.2 Spore fluorescence The degree of sample fluorescence is determined by observing the excitation colours when the samples are irradiated with UV light. This type of illumination causes certain components e.g. spores, algae, plant waxes, cutine, essential oils, oil to fluoresce. The fluorescence colour observed depends on the maceral type and maturity.

Table A1 Spore fluorescence scale:

1 Green yellow 2 Yellow 3 Light Orange 4 Mid-Orange 5 Dark Orange 6 Dark Orange 7 Red 8 Brown

The correlations between the fluorescence colour number, the maturity and all the other maturity parameters are displayed in Fig. A1. The SF technique is particularly useful for the maturity range Ro 0.3 to 1.0%. It can be extended to levels of maturity up to 1.3%. Fluorescence observation is also a useful tool to determine the extent and the amount of bitumen staining. 2.3 Spore colour This technique is extremely useful in the immature to early zone of oil generation. The technique uses transmitted light microscopy. The spore colour index (SCI) value is obtained by referring to the conversion table A2 below: Table A2 Spore colour conversion table 1.0 Colourless 1.5 Colourless – pale yellow 2.0 Pale yellow 2.5 Pale yellow-lemon yellow 3.0 Lemon yellow 3.5 Lemon yellow – golden yellow 4.0 Golden yellow 4.5 Deep yellow 5.0 Yellow orange 5.5 Light orange 6.0 Mid orange 6.5 Dark orange 7.0 Orange brown 7.5 Dark brown 8.0 Very dark brown 9.5 Brown black 10.0 Black SCI increases with increasing maturity. Fig A1. shows the correlation between SCI value, the oil window and other maturity parameters.

2.4 Pyrolysis (Rock Eval™) This screening technique provides parameters which are both measures of maturity and kerogen Type. Tmax can be a useful indicator of maturity; 435ºC±10% marks the transition from immature to mature organic matter. Values in the range 435 to 460ºC±10% represents peak oil generation (the oil window). Values of 455 to 460ºC±10% represent the transition from oil to wet gas generation. The Hydrogen Index (HI, defined under source rock evaluation) is also used as a maturity indicator (only where Type is constant). HI will decrease with increasing maturity as labile hydrogen-rich compounds leave the kerogen nucleus. 2.5 Gas chromatography (GC) GC analysis may be undertaken using a variety of gas chromatographs available to the market, equipped with suitable station and data integrators. A capillary column is normally used e.g. a 25m x 0.15mm id (narrow bore) fused silica column; wall coated with 0.12µm of cross-bonded non polar phase CP Sil5CB. The GC oven temperature is held at 50ºC for one minute, then raised to 320ºC at 5ºC-min. The interpretation of the n-Alkane distribution may reveal the maturity of the precursor source rock or the data may be compromised by secondary alternation processes. Careful interpretation will reveal which is the case. 2.6 Gas chromatography–mass spectrometry (GC-MS) Mass spectrometry is used to identify characteristic compounds found in oil and source rock extracts. It is a considerable more powerful and specific technique than GC FID. Many different MS systems are now available and instrumentation varies from laboratory to laboratory. Instruments are operated in either full scan (SCN) or Selected Ion Mode (SIM or SIR). The sample is ideally introduced using an ‘On Column’ technique. When the instrument is operated in SIR mode it is set to monitor specific ions specific to certain classes of biomarkers. Both aliphatic and aromatic hydrocarbons are monitored. At present the aliphatic groups monitored are the: triterpenoidal hydrocarbons (M/z 205, 191, 177, 123); steroidal hydrocarbons (M/z 217, 218, 231, 259 & 273). The aromatic steroidal hydrocarbons (M/z 259 & 231); Phenanthrenes (M/z 192 & 178), naphthalene and the methylated naphthalene compounds (M/z 142, 156, 179 & 184). Ratios are calculated for certain components (e.g. C29 Sterane 20S/2OS+R) whose stereochemistry depends on maturity; these ratios are normally calculated in the form of product/ (product + reactant).

3. Source rock evaluation 3.1 Bulk techniques 3.1.1 Total Organic carbon Total organic carbon (TOC) is determined by treating a small amount of the crushed samples with concentrated HCl to remove the inorganic carbon – ie the Carbonates. The samples is washed in distilled water, dried and analysed in duplicate in a LECO furnace. The measurement provides a direct determination of TOC present in rock samples. In general, shales with TOC values below 2% wt are not considered as prospective sources for the generation of commercial quantities of oil, slightly lower values of TOC may generate gas, assuming maturity and Type considerations are met. Table A3 None source <1% Poor source 1.0 to 2.0% Moderate >2.0% World class 5 to 10% Super rich 10%+ 3.1.2 Pyrolysis Once the amount of organic carbon has been established it is then necessary to determine the amount of hydrogen associated with the carbon. The higher the hydrogen contents relative to the carbon the better the source rock. The determination and other primary derived values are determined using Pyrolysis. Pyrolysis data are obtained using the Rock Eval method. Analyses are undertaken using the Rock Eval or Rock Eval OSA methods. A small amount (100mg) of the crushed sample, selected on the above criteria is weighed in a crucible, introduced to the furnace using an auto-sampler and progressively heated. Initially the temperature is raised to 100ºC and the volatile (gaseous) free hydrocarbons are driven of (Peak S0). The temperature is then ramped up to 300ºC and the heavier (liquid) hydrocarbons are driven off (Peak S1). The temperature is further increased to 550ºC. The higher temperatures result in the thermal degradation of any organic matter (kerogen) contained within the rock. All the released gases are detected by a flame ionisation detector (FID). Peaks S0, S1 and S2 are measured in mg HCg-1 rock. The temperature at which the kerogen breaks down most readily is referred to as Tmax. This value is a useful indication of source maturity. A guide to the interpretation of the S2 values and hence the hydrocarbon potential is given overleaf:

Table A4 Source richness Poor <2.5 mg HCg-1 rock Moderate 2 to 6 mg HCg-1 rock Good 6 to 20 mg HCg-1 rock Excellent >20 mg HCg-1 rock From the primary data a number of useful derived parameters may calculated. The two most useful derived parameters are: Hydrogen Index (HI) = S2/TOC*100 The HI is a measure of the hydrocarbon generating potential of the kerogen. The theoretical maximum is ~900 (similar to that of the values for a candle). Production Index (PI) = S1/S1+S2 (in OSA S1+S0/S1+S0+S2) See also table A1 PI when used in conjunction with other data from the well-bore is a useful indicator of the amount of cracking the kerogen has undergone. It is also useful to delineate zones of inward and outward migration. Tmax, HI and PI are dependent on maturity and kerogen Type. Tmax values for immature kerogens are <355ºC±10%. The peak oil window lies between 355ºC±10% and 455ºC±10%. Above 455ºC±10% only condensate and gas can be expected. With increasing maturity any generated gases will become progressively drier. It is thought that no further generation is possible beyond a Tmax of 500ºC; this is the maturity equivalent of a Vitrinite reflectance of Ro 3.0%. HI values will decrease with increasing maturity; the exact values will depend very much on the starting values. As an example HI values above 550 would indicate an immature highly aliphatic oil prone (Type I) kerogen. Values below 200 may indicate an immature non aliphatic rich kerogen or a mature formerly hydrogen-rich kerogen and so on. See Fig. A2. 3.2 Kerogen Type Optical techniques, microscopy During the measurement of maturity by all methods, a note is also made of the Amount and Type of kerogen. A classification using four broad kerogen times is often used:

Table kerogen Type Type I Algal, fluorescing sapropel, essential plant oils and resinous material Type II Spores, cuticles, pollen and amorphous sapropel (bacteriologically

degraded material) Type III Vitrinite Type IV Inertinite (primary of secondary and non-fluorescing amorphous

kerogen See also the Van Trevelyan diagram fig. A2 Samples containing sufficient Type I or Type II kerogens have the potential top generate oil; under increased thermal stress gas will be generated. Type III kerogens mainly generate gas with only minor quantities of oil/condensate, where as Type IV kerogens have little or no potential to generate anything. Typically source rocks will contain a mixture of kerogen types and as such can be thought of some kind of continuum often both in time and space between rarer and discrete end member kerogen types. (e.g. pure Alaginite or Sporinite or Vitrinite or Inertinite). The Type of kerogen present in the samples also provides some indication as to the environment of deposition. For example; algae, Type I kerogen, may indicate either lacustrine (eg Botryococcus) or marine (eg Tasmanites). Type II kerogens are largely confined marine shelfal environments. Type III kerogens are derived from continental organic matter, but terrestrial organic matter can be transported beyond the parallic swamps well into the marine resulting in a mixture of sources / source signatures. Primary Inertinite, Type IV kerogen, usually continental in origin, can also be transported into a variety of environments. The presence of Inertinite dilutes the source rock potential. All four kerogen Types are in fact convenient end members in a continuum. Determining the HI will give a bulk determination of oil or gas potential but HI values are less useful for a palaeoenvironmental examination. To establish environments of deposition a combined molecular and organic petrological-palynological approach is best used. Kerogen typing can also be used to help determine maturity. Organic matter becomes progressively darker with increasing maturity: the degree of darkness, called the Thermal Alternation Index (TAI) has been given an ascending series of values from approximately 2 to 4.

3.3 Molecular techniques and interpretation Gas chromatography (GC) Gas chromatography-mass spectrometry (GC-MS) Prior to undertaking a GC or GC-MS analysis a standard oil is analysed to ensure consistency and highlight any possible problems. n-Alkane distributions, biomarker and other compound presence and distribution profiles from solvent extracts can also provide useful information on kerogen type and depositional environment for the source rocks; this approach is used to examine the oils in detail to gain further information about presumed source rocks. The type of data may include: -the position of the n-Alkane maxima may indicate whether marine (C15 – C20) or terrestrial (C27 – C33) organisms have contributed to the kerogen. - the relative amounts of Pristane (Pr) and Phytane (Ph) are thought likely to indicate redox conditions that existed when the sediments were deposited. - there are numerous other useful parameters, to many to mention here. In addition, the presence of other compounds such as Isoprenoids and the distribution and quantity of unresolved material (UCM) are noted. Biomarker profiles derived from GC-MS analyses also contain valuable data which can provide clues as to the origin of the sediment. For example the ratio of C27:C28:C29 Steranes has been used extensively to differentiate between marine and terrestrial input (see Fig. A4): recent research has thrown doubt ion some of the usefulness of this an other ratios, so the best approach is to use the data in conjunction with all the other available data within a geological context. NB just because there are biomarkers present in shales it does not make those shales source rocks, a common error. A table of some of the GC-MS derived parameters and characteristic ions used by geochemical laboratories is included in the appendices (see table A4 & figure A4). Prior to any GC-MS run a standard oil is analysed to check the instrumentation. 4.1 Correlation, alteration and migration 4.1 Introduction GC and GC-MS and stable isotopes ratio techniques area also used in correlative, migration, oil alteration, compartmentalisation and other reservoir related studies The analysis of the stable isotopes of Carbon, Hydrogen, and Sulphur and to a lesser extent Nitrogen can be particularly useful in correlative, maturity, palaeoenvironmental, oil alteration and migration studies. The data are sued in conjunction with other geochemical parameters. In this particularly study stable isotopes, only, were used to help reconstruct the Palaeoenvironment. Figure A6

explains the notation and units used; Fig 5 shows the range of δC13‰ values/fractionations that occur in nature and Fig. 6 describes the stable carbon isotopic changes that occur in kerogens and their break down products (the basis on which to build Galimov isotope curves). Metal (Fe, Ni /Va) and sulphur content studies used in petroleum geochemistry are described elsewhere. 4.4.1 Correlations studies Using molecular and isotopic techniques possible oil : oil and oil : source rock relationships can be examined. The same data may also be used in migration studies. 4.2 Alteration studies Once reservoired or during migration, oil may become altered and many, if not nearly all the original characteristics lost. The principal modes of alteration are: biodegradation, waterwashing, asphaltene precipitation, UV alteration and evaporation. In all process expect asphaltene precipitation the resulting oil becomes heavier. Whilst these process will strip out various components, to include the biomarkers, to varying degrees, there are a number of ways correlative work can be still be undertaken e.g. Raney Nickel release of saturates from degraded crudes. 4.2.1 Biodegradation This also includes enzymic alteration. Biodegradation will only occur below a maximum temperature of 80±ºC. Additionally a supply of waterbourne nutrients is required. Biodegradations follows a set path, with the more readily digestible compounds being selectively removed first. These compounds are those that most closely resemble the product precursor molecules. To establish the extent of biodegradation in mature oils a scheme has been adopted from Alexander et al. 1983, see table A5. 4.2.2 Water washing The more water soluble components are removed sequentially by either ground water or formation waters (in the case of tar balls immersion in a sea or lake). Generally water-washing and biodegradation occur simultaneously. 4.2.3 Asphaltene precipitation This is an in-reservoir phenomenon only. Gas or low molecular weight hydrocarbons injected into the reservoir of oil will cause the asphaltenic compounds to precipitate out and ‘fall’ to the bottom of the oil column – more like be left at the bottom of the oil column. In reservoir gravity separation will also have similar results. Long migration pathways may result in the heaver, larger, asphaltenic complexes or molecules with greater stearic hindrances to be preferentially held back.

4.2.4 UV Alteration This is an exclusively surface effect. Therefore it will only be encountered only in oil slicks, tar balls and seeps and in surface pools of oil. UV irradiation eventually causes photochemical destruction of most hydrocarbon moieties. 4.2.5 Evaporation Again this is exclusively a surface effect. The lighter more volatile hydrocarbons will be preferentially lost.

Table A1 Correlation table: optical and molecular parameters

Marine (& some Lacustrine) Non-Marine Liptinite-rich* Kerogen-type Vtrinite/exinite/fusinite rich Phytoplankton & bacteria* Source organisms Higher plants & non-marine

algae

High H/c; low ‘O’ lipids Chemical composition Low H/C high ‘O’ lipids Polysaccharides etc polysaccharides, lignin, Sporo-pollen, lipids etc Major precursors for world Hydrocarbons Mainly gas, but some liquid oil reserves. Gas at higher generated h/c’s can be formed Maturity

• Note Typical marine kerogens contain a mixture of autochthonous marine and allochthonous terrigenous kerogen

• Note also lacustrine environments can also be liptinite rich Figure A3 Hydrocarbon source potential of marine and non-marine sediments, adapted from Tissot & Welte 1984

Stable Isotopes, δC13‰

End Cjmd June 1992, digitized 2008