Mineralogy and Organic Petrology of Oil Shales in the Sangkarewang Formation, Ombilin Basin, West Sumatra, Indonesia

Home , Inertinite, Kukersite, Maceral, Marinite, Siliciclastic, Tasmanite

Mineralogy and Organic Petrology of Oil Shales in The Sangkarewang Formation, Ombilin Basin, West Sumatra, Indonesia

Fatimah Student no: 3008511

SCHOOL OF BIOLOGICAL EARTH AND ENVIRONMENTAL SCIENCES

UNIVERSITY OF NEW SOUTH WALES

2009 ABSTRACT

The Ombilin Basin, which lies in Sumatra Island, is one of the Tertiary basins in Indonesia. This basin contains a wide variety of rock units, from pre-Tertiary to Quaternary in age. Significant oil shale deposits occur in the Sangkarewang Formation which was deposited during Paleocene-Eocene time. Several analyses have been carried out namely, XRD, XRF, carbon and sulphur determination, thin section petrology, polished section petrology as well as Fischer assay. These were intended to determine the inorganic and organic constituents of the Sangkarewang oil shale. Inorganic constituents of the Sangkarewang oil shale consist mainly of quartz, feldspar, carbonates and a range of clay minerals, together in some cases with minor proportions of sulphides, evaporites and zeolites. The organic matter in the oil shales of the sequence is dominated by liptinite macerals, particularly alginite (mainly lamalginite) and sporinite. Cutinite also occurs in some samples, along with resinite and traces of bituminite. The dominance of lamalginite in the liptinite components suggests that the material can be described as a lamosite. Samples from the Sangkarewang Formation have vitrinite reflectance values ranging between 0.37% and 0.55%. These are markedly lower than the vitrinite reflectance for coal from the overlying Sawahlunto Formation (0.68%), possibly due to suppression associated with the abundant liptinite in the oil shales. Fischer assay data on outcrop samples indicate that the oil yield is related to the organic carbon content. Correlations with XRD data show that, with one exception, the oil yield and organic carbon can also be correlated directly to the abundance of carbonate (calcite) and inversely to the abundance of quartz plus feldspar. This suggests that the abundance of algal material in the lake sediments was preferentially associated with carbonate deposition. High yields of oil are noted in some samples, as a percentage of the organic carbon content. This may indicate that partial generation of hydrocarbons from the material has already taken place, in association with thermal maturation of the Sangkarewang succession.

i CONTENTS

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Abstract i Contents ii List of Tables iv List of Figures v

Chapter 1. Introduction 1 1.1. Definition of oil shale 1 1.1.1. Practical definition 1 1.1.2. Petrographic definition 2 1.2. Classification of oil shale 7 1.2.1. Mineralogical classification 8 1.2.2. Petrographic classification 9 1.3. Origin of oil shale 12 1.4. Depositional environment of oil shale 16 1.5. An example of an oil shale deposit 19 1.6. Indonesian oil shale deposits 19 1.7. Objectives of the present study 21

Chapter 2. Geological Setting of the Ombilin Basin 22 2.1. Regional setting 22 2.2. Tectonic setting 26 2.3. Stratigraphy 31 2.3.1. Pre-Tertiary rocks 35 2.3.2. Tertiary rocks 37 2.4. Depositional history 48 2.5. Previous work on Ombilin Basin oil shales 49

Chapter 3. Geology of the Talawi Area 53 3.1. Introduction 53

3.2. Lithologic features 54 3.2.1. Pre-Tertiary rocks 55 3.2.2. Tertiary sedimentary rock units 57 3.2.3. Quaternary deposits 65 3.3. Stratigraphy 65 3.4. Structural geology 66

Chapter 4. Chemistry and Mineralogy of the Sangkarewang Oil Shale 67 Deposit 4.1. Chemical analysis 67 4.1.1. X-ray fluorescence analysis 69 4.1.2. Carbon and sulphur determination 75 4.2. Mineralogy 79 4.2.1. Background 79 4.2.2. XRD analysis techniques 83 4.2.3. Results 90 4.3. Evaluation of chemical and mineralogical data 92 4.3.1. Data from XRF analysis 92 4.3.2. Carbonate carbon and organic carbon 98 4.3.3. Comparison of XRD and XRF data 100

Chapter 5. Organic and Inorganic Petrology of the Sangkarewang Oil Shale 109 Deposit 5.1. Sedimentary petrography 109 5.1.1. Background 109 5.1.2. Analytical methods 111 5.1.3. Results 111 5.2. Organic petrology 114 5.2.1. Background 114 5.2.2. Analytical methods 116 5.2.3. Results 117 5.2.3.1. Organic constituents 117

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5.2.3.2. Vitrinite reflectance 121 Chapter 6. Oil Yield and Spent Shale Residues of the Sangkarewang Oil 125 Shale Deposit 6.1. Oil shale assays 125 6.1.1. Background 125 6.1.2. Analytical methods 126 6.1.3. Results 130 6.1.4. Relation of oil yield to other shale properties 130 6.2. Mineralogy of spent oil shale residues 134

Chapter 7. Conclusions 139 References 143

Acknowledgements 151

LISTOFTABLES

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Table 4.1. List of samples analysed 68

Table 4.2. Chemical composition of oil shales (Greensmith, 1978) 69 Table 4.3. Major element oxides from X-ray fluorescence analysis 73 Table 4.4. Minor elements from X-ray fluorescence analysis, expressed 74 as oxides Table 4.5. Results of sulphur and carbon analysis 77 Table 4.6. Sulphur obtained by calculation 78 Table 4.7. Classification of the clay minerals (Grim, 1953) 80 Table 4.8. Classification of phyllosilicates related to clay minerals 81 (Weaver, 1989, modified from Bailey, 1980b) Table 4.9. Classification of phyllosilicates with emphasis on clay 81 minerals (Moore and Reynolds, 1997) Table 4.10. Clay classification of Velde (1992) 82 Table 4.11. Siroquant results for typical oil shale sample (SR 15) 90

Table 4.12. Quantitative percentages of minerals identified in samples 91 studied using powder XRD and Siroquant Table 4.13. Calculation of oxide composition from mineral indicated by 101 Siroquant Table 4.14. Example of oxide composition calculation for SR 5 101 Table 5.1. Vitrinite reflectance for samples from the Sangkarewang 122 deposit Table 6.1. Example of modified Fischer assay spreadsheet 129 Table 6.2. Fischer assay data for samples from the Sangkarewang oil 130 shale deposit

LISTOFFIGURES

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Figure 1.1. Van Krevelen diagram, showing the respective evolution path 4 of kerogen Figure 1.2. Maceral classification according to the subdivisions of the 5 Stopes-Herleen classification (Ward, 1984) Figure 1.3. Classification of sapropelites and sapropelic coals (Hutton et 10 al., 1980) Figure 1.4. Classification of organic-rich rocks (Hutton, 1987) 10 Figure 1.5. Secondary division of oil shales giving important properties of 13 each oil shale (Hutton, 1987) Figure 1.6. Important properties of oil shales and characteristics of 14 deposits (Hutton, 1987) Figure 2.1. Outline map of Sumatra, showing the location and extent of 23 the Ombilin Basin (de Smet, 1991). Figure 2.2. Geologic map of the Ombilin Basin (Koesoemadinata and 25 Matasak, 1981)

Figure 2.3. Idealised geologic cross section through the northern part of 27 the Ombilin Basin (Koesoemadinata and Matasak, 1981) Figure 2.4. Idealised geologic cross-section through the southern part of 28 the Ombilin Basin (Koesoemadinata and Matasak, 1981) Figure 2.5. Tectonic setting of Indonesia (Koesoemadinata and Matasak, 29 1981) Figure 2.6. Tectonic setting of Sumatra (Koesoemadinata and Matasak, 30 1981) Figure 2.7. Diagrammatic cross-section across Central Sumatra showing 33 the tectonic setting of the Ombilin Basin (Koesoemadinata and Matasak, 1981) Figure 2.8. Stratrigraphic sequence in the Ombilin Basin as defined by 34 different authors (de Smet, 1991) Figure 2.9. Vitrinite reflectance values and spore colour index profiles 43 from Sinamar No.1 (Koning, 1985) Figure 2.10. Stratigraphic units of the Ombilin Basin in the Sinamar No. 1 46 well (Koning, 1985) Figure 2.11. Typical saturate fraction gas chromatograms derived from 51 outcrop samples of the Sangkarewang Formation (Williams et al, 1995) Figure 3.1. Location map of the study area. 54 Figure 3.2. Thin section of granite from Padang Ganting (SR-43) 56 Figure 3.3. Thin section of granite from Ampang Nago (SR-42) 56 Figure 3.4. The Permian Silungkang Formation near Muara Kelaban 57 village Figure 3.5. Breccia of the Brani Formation exposed in the area north of 58 Sawahlunto town Figure 3.6. Thin section of Brani breccias in Sawahlunto town 59 Figure 3.7. Brani breccia with Sangkarewang shale fragment in 60 Malakutan River Figure 3.8. Outcrop of the Sangkarewang shale in Sawahlunto area, close 61 to the Sumpahan River

Figure 3.9. Turbidite sandstone intercalated Sangkarewang shale in 61 Ampang Nago River

Figure 4.1. A calibrated graph for K2O from the Philips PW 2400 72 calibration process Figure 4.2. Sample holder (“boat”) to be analysed by LECO CNS-2000 76 Figure 4.3. Sample on boat being inserted into LECO CNS-2000. 76 Figure 4.4. A powdered sample on an aluminium cavity sample holder in 84 the centre of XRD goniometer chamber Figure 4.5. Philips goniometer with the sample chamber on the centre 84 Figure 4.6. Preparation of oriented aggregates of clay fractions, showing 85 beakers for settling in the background and glass slides with clay concentrates in the foreground Figure 4.7. XRD pattern from SR 37 (powdered, glycolated and heated up 87 to 400oC) Figure 4.8. X-ray diffraction data from SR 15, showing the observed 89 diffractogram, the synthetic diffractogram obtained by Siroquant analysis, and the difference between them

Figure 4.9. Correlation between SiO2 and loss on ignition (LOI) for 93 samples from the Sangkarewang Formation

Figure 4.10. Correlation between CaO and SiO2 for samples from the 93 Sangkarewang Formation Figure 4.11. Correlation between CaO and LoI for samples from the 93 Sangkarewang Formation

Figure 4.12. Correlation between Al2O3 and K2O for samples from the 94 Sangkarewang Formation

Figure 4.13. Correlation between Al2O3 and TiO2 for samples from the 94 Sangkarewang Formation

Figure 4.14. Correlation between Na2O and SO3 for samples from the 94 Sangkarewang Formation Figure 4.15. Correlation between CaO and MgO for samples from the 95 Sangkarewang Formation

Figure 4.16. Correlation between CeO2 and PbO for samples from the 95

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Sangkarewang Formation

Figure 4.17. Correlation between CeO2 and U3O8 for samples from the 95 Sangkarewang Formation

Figure 4.18. Correlation between ThO2 and U3O8 for samples from the 96 Sangkarewang Formation

Figure 4.19. Correlation between ZrO2 and CeO2 for samples from the 96 Sangkarewang Formation

Figure 4.20. Correlation between ZrO2 and ThO2 for samples from the 96 Sangkarewang Formation

Figure 4.21. Correlation between ZrO2 and U3O8 for samples from the 97 Sangkarewang Formation Figure 4.22. Correlation between carbonate carbon and calcite as 99 determined by XRD Figure 4.23. Correlation between organic carbon and calcite content 99

Figure 4.24. Comparison between SiO2 obtained from chemical analysis 102

(XRF) and SiO2 deduced from the Siroquant analysis

Figure 4.25. Comparison between Al2O3 obtained from chemical analysis 103

(XRF) and Al2O3 deduced from the Siroquant analysis

Figure 4.26. Comparison between Al2O3 and Fe2O3 obtained from 104

chemical analysis (XRF) and Al2O3 and Fe2O3 deduced from the Siroquant analysis Figure 4.27. Comparison between CaO obtained from chemical analysis 105 (XRF) and CaO deduced from the Siroquant analysis Figure 4.28. Plot of calcite determined by Siroquant against carbonate 105 carbon determined by the LECO analyser

Figure 4.29. Comparison between Na2O obtained from chemical analysis 106

(XRF) and Na2O deduced from the Siroquant analysis

Figure 4.30. Comparison between K2O obtained from chemical analysis 107

(XRF) and K2O deduced from the Siroquant analysis Figure 4.31. Comparison between MgO obtained from chemical analysis 107 and MgO deduced from the Siroquant analysis Figure 4.32. Comparison between Loss on Ignition obtained from chemical 108

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analysis (XRF) and H2O + CO2 deduced from the Siroquant analysis Figure 5.1. Thin section of sandstone of sandstone from Talawi area (SR 112 16) Figure 5.2. Altered plagioclase and biotite in sandstone from the lower 113 Sangkarewang sequence (SR 43) Figure 5.3. Thin section of SR 21 113 Figure 5.4. Zeiss Axioplan microscope connected to a Leica DC 300F 117 camera and Kodak Imaging software for image capture Figure 5.5. Lamalginite in SR 35 119 Figure 5.6. Sporinite in SR 19 surrounded by lamalginite 119 Figure 5.7. Resinite filling cell cavities of vitrinite (SR 19) 120 Figure 5.8. Elongate particles with orange fluorescence, possibly cutinite 120 (SR 44) Figure 5.9. Lamalginite and fish bones in SR 19 120 Figure 5.10. Fish remains in SR 19 121 Figure 5.11. Vitrinite in coal of the Sawahlunto Formation (SR 28) with 121 liptinite macerals Figure 5.12. Plot showing stratigraphic variation in vitrinite reflectance 124 values Figure 6.1. Modified Fischer assay retort 127 Figure 6.2. Oil shale retorting unit 129 Figure 6.3. Plot of oil yield against organic carbon content, as determined 131 by LECO CNS analyser Figure 6.4. Plot of oil yield against calcite content, as determined by XRD 132 analysis Figure 6.5. Plot of oil yield against quartz plus feldspar, as determined by 133 XRD analysis Figure 6.6. Plot of oil yield against total clay minerals, as determined by 133 XRD analysis Figure 6.7. Plot of oil yield against calcite plus clay minerals, as 134 determined by XRD analysis

Figure 6.8. Comparison between diffractograms of raw shale from SR 11 135 and the corresponding spent shale Figure 6.9. Comparison between diffractograms of raw shale from SR 35 136 and the corresponding spent shale Figure 6.10. Comparison between diffractograms of raw shale from SR 17 136 and the corresponding spent shale Figure 6.11. Comparison between diffractograms of raw shale from SR 37 137 and the corresponding spent shale Figure 6.12. Comparison between diffractograms of raw shale from SR 19 137 and the corresponding spent shale Figure 6.13. Comparison between diffractograms of raw shale from SR 14 138 and the corresponding spent shale

APPENDIX

Appendix 1: Geological map of the Talawi area and its vicinity, West Sumatra Province, Indonesia.

Appendix 2: Reprint of “Mineralogy and Organic Petrology of Oil Shales in The Sangkarewang Formation, Ombilin Basin, West Sumatra, Indonesia” – a paper published on International Journal of Coal Geology, Vol. 77, issues 3-4, 2008.

CHAPTER 1

INTRODUCTION

1.1. Definition of Oil Shale

Oil shale can be defined in different ways depending on the purpose of the definition. For the purposes of the present study, oil shale is defined from two different points of view: a practical definition and a petrographic definition.

1.1.1. Practical definition

Gavin (1924) defined oil shale as a compact, laminated sedimentary rock, producing in excess of 33% of ash and containing organic matter that produces oil upon distillation. However, extracting by ordinary solvents used for petroleum cannot produce significant quantities of oil. Nevertheless, there is no detailed explanation of the relative amount of oil product considered as being ‘a significant value’.

Duncan (1976) described oil shale as a fine-textured rock of sedimentary origin that contains indigenous organic matter, mainly insoluble in ordinary petroleum solvents, from which substantial amounts of oil can be extracted by heating. The oil yield from the retorting process ranges from about 4% to more than 50% of the weight of the rock, or about 38-570 litres of oil per tonne of rock (10-150 US gallons of oil per ton of rock).

For practical engineering purposes, Lee (1991) identified oil shale as “a shale rich in organic matter and which, when heated or subjected to destructive distillation, yields an oil or gaseous hydrocarbon”.

1 Several other definitions of oil shale can be found from different references, but still no more specific definition has been proposed. Although Tissot and Welte (1978) concluded that “there is actually no geological or chemical definition of an oil shale”, they considered oil shale as any rock of shallow depth origin that produces commercial amounts of oil upon pyrolysis.

Similarly, Greensmith (1978) concluded that there is no completely satisfactory definition of oil shale. He believed that the most appropriate definition of oil shale is ‘a fine-textured rock, normally laminated, containing organic matter from which substantial amounts of oil can be extracted by heating’.

On the basis of yield, oil shale can be defined as a sedimentary rock that yields oil. In practical terms it probably should yield more oil than the energy-equivalent amount required to heat the shale to get the oil out.

1.1.2. Petrographic definition

Oil shale can also be defined based on the types of organic matter present. The proportions of total organic matter in shales, carbonates, and sandstones average 2.1%, 0.29%, and 0.05%, respectively.

According to Taylor et al (1998), oil shales are sedimentary rocks or unconsolidated sediments that contain large amounts of immature or marginally mature organic matter with a high hydrocarbon generation potential. An oil shale must have a significant proportion of organic material to be of economic interest. The organic matter contained in the oil shales is mainly a solid material or kerogen, insoluble in organic solvents. Generally, the organic matter in oil shales and associated rocks is referred to by two terms, namely bitumen and kerogen (Hutton, 1987).

Bitumen is a native substance of variable color, hardness and volatility, composed principally of the elements carbon and hydrogen and sometimes associated mineral matter, with the non-mineral constituents being largely soluble in carbon disulphide.

2 Kerogen is a term used to describe the organic constituents of sedimentary rocks insoluble in organic solvents (Tissot and Welte, 1978). The term kerogen (‘oil-former’) was first used with reference to the carbonaceous matter in Scottish shales, which gave rise to crude oil on distillation. Kerogen is the major organic component in petroleum source rocks and shales in general. Kerogen constitutes the bulk of the organic carbon in the sedimentary rocks of the earth’s crust, and is mainly present in highly dispersed form.

Chemically, kerogen consists of a mixture of large organic molecules, such as those constituting certain waxes and fats (lipids), certain oils and pigments (isoprenoids and terpenoids), and certain resins (steroids).

Optical examination and physicochemical analyses can be used to identify several different types of kerogen. Kerogen can be classified into four types, based on the hydrogen/carbon ratio versus the oxygen/carbon ratio. The respective evolution path of kerogen is illustrated in the van Krevelen diagram (Figure 1.1).

The organic matter in oil shales mainly consists of macerals, which are the microscopically recognizable individual constituents of sedimentary organic matter. The macerals are usually classified within one of the three maceral groups: vitrinite, inertinite, and liptinite or exinite (International Committee for Coal Petrology, 1971).

Each maceral can be distinguished by its optical characteristics, the relief of its polished surface and its morphology, as well as its reflectance and fluorescence characteristics.

Of the three maceral groups: 1. Vitrinite is coalification products of humic substances, which essentially originate from plant tissue (stems, roots, leaves, bark). They have reflectance values between 0.2 and 0.5% under oil immersion (R.I. 1.518, wavelength 546nm) in lower rank (lignite and sub bituminous) coals, 0.5 to 2.0% in bituminous coals and up to 8% in anthracites. 2. Liptinite (exinite) is derived from waxy, hydrogen-rich types of plant remains such as sporopollenin, resins, waxes and fats. They have lower reflectance than vitrinite,

3 with a yellow color in thin section. Under blue-violet illumination, the liptinite macerals can be recognized by their distinct fluorescence, especially in low-rank coals and in oil shales. 3. Inertinite is derived mostly from the same original plant substances as vitrinite and liptinite, but mainly represent materials that were oxidized prior to burial. Inertinite macerals are characterized by high reflectance values and a light grey color when studied in polished section.

Figure 1.2 illustrates the maceral classification according to the subdivisions of the Stopes-Heerlen classification (Taylor et al., 1998).

Figure 1.1. Van Krevelen diagram showing four types of kerogen at different maturity levels. Symbols are type I, Eocene Green River shale, United States; type II, Jurassic of Saudi Arabia and Toarcian shale of France; type III, Tertiary of Greenland; and type IV, Upper

Tertiary, Gulf of Alaska. The dashed lines are isorank lines based on vitrinite reflectance, %Ro. The arrows show the direction of increasing maturity. (Data from Jones 1987; Peters, 1986)

4 Of the three maceral groups, the most important in oil shale study is the liptinite group. Most oil shales contain abundant liptinite with minor vitrinite and inertinite; some oil shales contain bitumen. Inertinite and vitrinite are generally rare in oil shales, with the exception of the sapropelic coals. Hutton (1987) defined oil shale as “any rock containing 5vol%, or more, liptinite”. This definition needs more explanation, as some coals also contain more than 5% liptinite. Although liptinites are relatively rare in coal (typically around 5% by volume), sapropelic coal, which is included within the definition of oil shale for the present study, consists mainly of liptinite.

Figure 1.2. Maceral classification of brown coals and lignites in the Stopes-Harleen system (After International Committee for Coal Petrology 1971, 1975, 1985)

Liptinite originates from relatively hydrogen-rich plant materials such as sporopollenin, cutin, suberin, resin, waxes, balsams, latex, fats and oils, as well as from bacterial degradation products derived from proteins, cellulose and other carbohydrates. The liptinite precursors are relatively stable; during the peatification and diagenesis of brown coals they do not undergo humification and gelification. The liptinite in oil shale is derived from numerous organisms that lived in several different environments.

5 Liptinite macerals can be identified in more detail from their fluorescence characteristics under blue light. Taylor et al (1998), Ward (1984), ICCP (1971) and Hutton (1982, 1987) have described the properties of individual macerals of the liptinite group.

Individual macerals of the liptinite group are: a. Sporinite which originates from the outer cell walls of spores and pollen, and consists of round, lenticular and flattened bodies mostly 0.01 to 0.25 mm in size. b. Cutinite which originates from cuticular layers and cuticles, formed within the outer walls or the epidermis of leaves, stems and other aerial parts of plants. c. Resinite which occurs as circular, oval or rod-like resin bodies. Although the origin of resinite may be varied, resins and waxes are considered to be the principal precursors. Other source materials of resinite are balsam, copals, latex, oil and fats. d. Liptodetrinite originates from various substances, including fragments and fine degradation remnants of sporinite, cutinite, resinite, alginite and suberinite. e. Alginite originates from algae, which were mainly decay-resistant and oil-rich. Two types of alginite can be distinguished: telalginite (spherical to disc-shaped bodies) and lamalginite (fine lamellar bodies). Generally, typical alginite is found in profusion only in oil shales and sapropelic coals. f. Suberinite is derived from corkified cell walls, which occur mainly in barks, at root surfaces, on stems and on fruits, acting as a desiccation protector. g. Fluorinite. The precursor of fluorinite was an essential oil. Under blue light excitation, fluorinite has very strong yellow to greenish-yellow fluorescence in brown coals and low rank bituminous coals. h. Exsudatinite is a solid bitumen, probably of asphaltic nature, similar to gilsonite, grahamite and other solid asphaltic exudates which occur in vein- and dyke-like bodies traversing rock sequences. i. Bituminite probably originates as bacterial decomposition products of algae and faunal plankton, together with much bacterial biomass. It may be found as a groundmass as well as in laminae or pods.

Most forms of organic matter in oil shale are included within the liptinite group of macerals. They are largely algal in origin (alginite), with a lesser contribution from

6 spores, pollen and cuticle of higher land plants (sporinite, cutinite). The organic matter is mostly autochthonous or hypautochthonous in origin (Hutton et al, 1980).

Kerogen can be divided into four different types (Tissot and Welte, 1978). The organic matter in Type-I kerogen is composed mainly of alginite macerals, whereas the organic matter in Type-II kerogen is composed of sporinite or other types of liptinite macerals. Type-III kerogen is dominated by vitrinite/huminite macerals while Type-IV kerogen is dominated by inertinite macerals.

The organic matter in oil shales can mainly be categorized as Type-I and Type-II kerogen, which is derived mainly from liptinite group macerals. In the case of tar sands, the organic matter is a mixture of alteration products derived from biodegradation, metamorphism or maturation of other organic matter. A tar sand is a sedimentary rock (consolidated or unconsolidated) that contains bitumen (solid or semisolid hydrocarbons) or other heavy petroleum components that, in their natural state, cannot be recovered by conventional petroleum-recovery methods. This condition usually applies to oils having a gravity of less than 12o API.

Rocks containing organic matter that have been buried to great depth do not represent potential oil shales, even if subsequent folding and erosion has brought the rock back close to the ground surface. It can be said that the equivalent of an oil shale, sufficiently buried, constitutes a petroleum source rock. However, the reverse (i.e. that the equivalent of a petroleum source rock, shallowly buried, constitutes an oil shale) is not necessarily true, due to the requirement of richness or overall abundance of organic matter.

1.2. Classification of Oil Shale

Oil shale can be classified by several different approaches. In the present study, the classification of oil shale is based on two criteria: mineralogy and petrology.

7 1.2.1. Mineralogical classification Duncan (1976) classified oil shale into three different kinds, based on the mineral composition of the oil shale. 1. Carbonate-rich shale 2. Siliceous shale 3. Cannel shale

1. Carbonate-rich shale This type of oil shale contains substantial amounts of carbonate minerals, commonly calcite or dolomite with a fine-grained texture, which are the dominant mineral constituents of the rock. Most of the carbonates were probably precipitated at the time of deposition of the shale, but some of them may have formed as a result of alteration of the organic debris. The process of oxidation of part of the organic

matter to CO2 and the combination of CO2 with calcium, magnesium and other elements may have begun with the decay of organic matter during deposition and continued during the early stages of compaction of the shale.

Carbonate-rich oil shale, particularly that of lacustrine deposition, is characterised by cyclic layers rich in organic matter alternating with cyclic layers composed mostly of carbonate. These shales are generally hard, tough rocks that are resistant to weathering. The process of compaction and cementation evidently sealed the volatile and mobile constituents in the rock at a very early stage.

2. Siliceous shale This type of oil shale has detrital silicate minerals (quartz, feldspar, or clay) as the main constituents, without significant proportions of carbonate minerals. Chert or opal, sometimes in the form of diatoms and other fossil remains, are not uncommon. Siliceous oil shales are generally dark brown or black, and are less resistant to weathering than carbonate-rich shales. In many cases the effects of compaction, deformation and metamorphism have apparently led to the progressive release and migration of the mobile and volatile constituents.

8 3. Cannel shale Cannel shale is an oil shale that burns with a bright flame, and consists predominantly of organic matter that completely encloses other mineral grains. Such rocks are sometimes classed as impure cannel coals, torbanites, or some varieties of marine coals. Cannel shale, as defined by Duncan (1976), is composed largely of algal remains, and generally contains so much mineral impurity that it is excluded from commercial categories of coal. A large proportion of its organic matter is convertible to oil with normal distillation methods. The oil yield of cannel shales does not seem to be appreciably affected by compaction, and does not diminish with age.

1.2.2. Petrographic classification Based on the type of organic matter in the rock, Hutton et al. (1980) classified oil shale into two categories as described in Figure 1.3. In this classification, oil shale is divided into sapropelite and sapropelic coal.

Later on, in 1987, Hutton proposed another classification of organic-rich rocks. In this classification, the organic-rich rocks were divided into four categories: oil shales, bitumen–impregnated rock, humic coals and tar sands (Figure 1.4.). This classification also revised the oil shale classification of Hutton (1980).

The organic matter in oil shales is derived from a variety of organisms, which include precursors of terrestrial, lacustrine and marine origin. Hence, a natural classification of oil shales should include these terms as a basis for a primary subdivision. Thus the three major types of oil shales defined by Hutton (1987) are (Figure 1.4.): a. Terrestrial Oil Shale: Oil shale composed of liptinite derived from terrestrial organisms.

9 b. Lacustrine Oil Shale: Oil shale composed of liptinite derived from dominantly lacustrine (including brackish, saline or freshwater lacustrine) organisms; and c. Marine Oil Shale: Oil shale composed of liptinite derived from dominantly marine organisms.

Oil Shale

Sapropelic Coal Sapropelite

Cannel Boghead Tasmanite Kukersite Lamosite (torbanite or kerosene shale)

Boghead-Cannel Cannel-Boghead Mixed Oil Shale Mixed Oil Shale

Figure 1.3. Classification of sapropelites and sapropelic coals (Hutton et al., 1980)

Coal Oil shale Bitumen-impregnated rock Tar sand

Humic Terrestrial Lacustrine Marine Naphtene- Asphaltene- rich rich

Vitrain Cannel Lamosite Marinite Gilsonite Albertite Oil Clarain Coal Torbanite Tasmanite Grahamite Wurtzilite Bitumen Durain Kukersite Fusain

Figure. 1.4. Classification of organic-rich rocks (Hutton, 1987).

Hutton (1987) further divided these three major types of oil shale into secondary groups (Figure 1.4), based on the type and quantity of the included liptinite. These secondary groups are as follows:

1. Cannel coal Cannel coal is a brown to black, homogenous oil shale composed of liptinite derived from terrestrial vascular plants, and also generally containing vitrinite and inertinite.

2. Torbanite Torbanite is a black to greenish-black oil shale in which the principal liptinite is telalginite derived from Botryococcus-related, lacustrine algae.

3. Lamosite Lamosite is a pale brown to dark greyish-brown oil shale in which the principal liptinite is lamalginite derived from lacustrine algae and other phytoplankton. Based on type localities, Hutton (1987) subdivided lamosite into a Rundle type and Green River type. Rundle type refers to the oil shale deposits in the Rundle area, Australia, whereas the Green River type refers to the oil shale deposits in the Green River Formation of Wyoming, United States.

4. Marinite Marinite is a grey to dark greyish-black oil shale in which the principal liptinites are lamalginite derived from marine algae and other phytoplankton and/or bituminite derived from marine precursors.

5. Tasmanite Tasmanite is a dark grey to black oil shale in which the principal liptinite is telalginite derived from marine tasmanitids.

6. Kukersite Kukersite is a brown oil shale in which the principal liptinite is telalginite from Gloeocapsomorpha prisca.

The organic matter in these oil shales is derived from a variety of organisms, which include precursors of terrestrial, lacustrine and marine origin. Additional details are given in Figure 1.5. Figure 1.6, based on the work of Hutton (1987) describes several other important properties of the different oil shale groups and the characteristics of particular oil shale deposits.

1.3. Origin of Oil Shale

Oil shales result from the contemporaneous deposition of fine-grained mineral debris and organic degradation products derived from the breakdown of biota. Conditions required for the formation of oil shales therefore include abundant organic productivity, early development of anaerobic conditions, and a lack of destructive organisms.

Thorne et al. (1964) suggested that: “oil shale was formed by the deposition and lithification of finely divided mineral matter and organic debris in the bottom of shallow lakes and seas. The organic debris resulted from the mechanical and chemical degradation of small aquatic algal organisms”.

12 TERRESTRIAL LACUSTRINE MARINE OIL SHALE OIL SHALE OIL SHALE

Lithotype CANNEL COAL TORBANITE LAMOSITE MARINITE TASMANITE KUKERSITE

RUNDLE TYPE GREEN RIVER TYPE

Precursor Organisms Vascular plants Green algae Green algae ?Blue-green algae Green algae Green algae Green algae Acritarchs Dinoflagellates

Growth Form Various Planktonic colonial Planktonic colonial Benthonic algae? Planktonic Unicellular Planktonic colonial Unicellular Algal ooze Unicellular

Dominant Maceral/ Sporinite Telalginite Lamalginite Lamalginite Lamalginite Telalginite Telalginite Constituent Resinite Bituminite Cutinite

Known Precursor Angiosperms Pila Pediastrum Nostocopsis Tasmanites Gloeocapsomorpha Gymnosperms Reinschia Saptodinium ? Lelosphaer- prisca Cleisto- idium Sphaeridium

Related Organisms Various Extant Botryococcus braunii Pediastrum Extant Blue-Green Algae Various Extant Pachysphaera pelagica Botryococcus braunii Vascular plants Algae Acritarchs Dinoflagellates

Other Organic - Minor Vitrinite Vitrinite Telalginite Bitumen - - - Matter Inertinite Inertinite Vitrinite

- Trace Telalginite Sporinite Sporinite Vitrinite Telalginite Vitrinite Bituminite Resinite Bitumen Sporinite Vitrinite Inertinite Inertinite Lamalginite - Sporinite Bitumen

Figure. 1.5. Secondary division of oil shales giving important properties of each oil shale (Hutton, 1987).

Cannel coal Torbanite Lamosite Marinite Tasmanite Kukersite

Rundle type Green River type

Precursor Terrestrial Planktonic Planktonic Benthonic Planktonic Planktonic Planktonic Plants Algae Algae Algae Algae Algae Algae

Environment Peat swamp Lacustrine in Fresh to Stratified or Marine Shallow Shallow of deposition a peat swamp brackish lake saline lake marine marine

Hand Black to Black to Olive-grey, Brown, Grey to Dark grey Brown, specimen brown, brittle greenish – brown to dark laminated dark to black, massive black, greyish- greyish massive to conchoidal brown, black, laminated fracture massive to massive to laminated laminated

Age Carboniferous Carboniferous Carboniferous Tertiary Cambrian Permian Ordovician to Tertiary Permian Tertiary Cretaceous to Jurassic Cretaceous

Resources Small Small Large Very large Small Large

Seam Variable 0.2-2 30-75 15-130 1-10 1-2 1-3 thickness (m) Seam Variable Lensoidal Laterally Laterally Laterally Lensoidal Laterally geometry persistent persistent persistent persistent

Average yield 60-100 230-800 60-130 135 60-80 115-150 210-320 (L/tonne) Maximum 300 1090 320 460 150? 290t 400? yield (L/tonne) 550a

Figure. 1.6. Important properties of oil shales and characteristics of deposits (Hutton, 1987)

There are three factors in the formation of oil shale (Cane, 1976): a. Conditions of environment b. Conditions of deposition. c. Diagenetic processes a. Conditions of Environment The formation of oil shale, as well as the production of petroleum, requires suitable environmental conditions such as abundant organic matter production, early development of an anaerobic environment, and absence of total destructive organisms. Oil shales were mainly formed in tranquil environments such as lakes, lagoons or shallow seas. The main source of the deposits was algal remains, with spores, pollen, and higher plant remains as additional minor contributors.

14 b. Conditions of Deposition The aqueous environment from which the kerogen precursors were derived was characterised by very tranquil conditions. It could include small or large lakes, a series of interconnected lagoons, or even inland seas as the sites for fresh-water deposits. Other possibilities for oil shale formation are river deltas or shallow estuaries. In addition, some types of oil shale were formed under marine conditions, in shallow coastal ecosystems of quiet bays and lagoons or temporary inshore basins.

The inland water areas were usually surrounded by a thick margin of swamp vegetation, which acted as an effective filter for all but the finest silt and clay brought in by rivers. The fine-grained material consisted mostly of clays, plus finely comminuted plant debris. Coarser matter and much mud were introduced during flood periods. Inflowing rivers brought further organic matter, which, together with clay and silt, was mixed in various proportions with the autochthonous matter of the lakes.

All deposits are micro-stratified, and contain banded structures indicating that the materials were not deposited in a steady environmental condition. These structures were produced by variation with the seasons, on an annual or irregular basis.

After the depositional stage, successive layers of sediments covered the composite, decaying debris-mineral matter stratum. With subsidence over geological time, the pressure of the overlying strata resulted in the compaction of the mixture and the final chemical changes took place. c. Diagenetic Processes The complete process of oil shale formation probably did not occur at temperatures more than 150o C, and the chemical composition changes were beginning at the time of deposition. The maturation process of algal mats, polymerization and biochemical decay would cause a decrease in chemical unsaturation whereas proteins and carbohydrates would be preferentially removed under aerobic and anaerobic conditions. At this process, protein and carbohydrates would preferentially vanish under aerobic and anaerobic conditions. Later on, under anaerobic conditions, polyene fatty

15 acids would lose carboxylic and other groups by condensation or bacterial attack. The main composition changes in the early stage of diagenesis were polymerization and loss of oxygen. Some oxygen was lost as water because of condensation reactions, and a further quantity was converted by anaerobes (Cane, 1976).

Throughout all these changes, more stable forms of organic matter were created at the expense of the less stable ones. The effect of thermal maturation was a uniform decrease in oxygen of the proto-kerogen, and the generation of an essentially hydrocarbon structure. The final product was a tough inert organic polymer that bound together a reinforcing inorganic filler. This product constitutes oil shale.

Cane (1976) divided oil shales into three types, some of which are further discussed in the later work of Hutton (1987). The origin of each type was described by Cane (1976) as follows:

1. Torbanite originated from a morphologically recognisable colonial alga of terrestrial and fresh-water origin. The deposits are lenticular and (in Australia) are associated with Permian coals. 2. Tasmanite is constituted from spherical disseminules of organised structure, believed to be algae of (then) unknown affinity. The deposits are stratified and of marine origin. In this case, the chemical nature of the kerogen has only partially been explored, unlike (Australian and other) torbanites, the character of whose kerogen is quite well established. 3. Green River Formation oil shale is composed of disorganised and (then) unrecognisable organic matter. Even though it was thought to be mainly of algal origin, it also appeared that several biological types had contributed to the organic matter. The sediment is of lacustrine origin associated with saline waters.

1.4. Depositional Environment of Oil Shale

Most oil shales were deposited under anoxic or oxygen-deficient bottom water (Taylor et al, 1998). Duncan (1976), Tissot and Welte (1978), Greensmith (1978) and

16 Hutton et al (1980) have reviewed the main geological environments in which oil shales are deposited. To summarize, there are three types of oil shale depositional environments, namely: 1. Large lake basins 2. Small lake basins 3. Shallow seas

The following gives a detailed explanation for each type.

1.4.1. Large lake basins

Large lake basins, those of tectonic origin in particular, are mainly formed during mountain construction. The oil shales deposited in large lacustrine basins are typically of the calcareous type. Mineralogically, these oil shales are marls or argillaceous limestones. The associated sediments could be volcanic tuffs, clastics and carbonate rocks, as well as saline minerals (as in the Green River Formation). Tuffaceous sediments are frequently interspersed with the oil shales or closely interbedded with fine-grained limestones.

Saline minerals represent extensive evaporite beds, which formed during prolonged phases of aridity and desiccation. Some examples of this type are the oil shales of the Green River Formation of Eocene age in the western United States, the Albert Shale of Early Carboniferous (Mississippian) age in New Brunswick, Canada, and deposits of Triassic age in the Stanleyville Basin of the Congo.

The Green River deposit is the thickest oil shale deposit known (Duncan, 1976). It thickens substantially toward the centre of its host basin, where the strata are as much as 600 m (2,000 feet thick). The oil shales may extend over thousands of square kilometres and produce up to 150 litres of oil per tonne (40 gallons per ton) or more of oil with distillation.

17 1.4.2. Small lake basins

Although these basins are only small depressions in swampy areas, many small lake basin oil shale deposits are of high grade, producing over 35 litres (1 barrel) of oil per tonne of rock. Some are both thick and of wide extent, as in the Tertiary deposit at Fushun, Manchuria (Duncan, 1976).

1.4.3. Shallow seas on continental platforms and continental shelves

These basins represent large stable blocks on continental platforms or shelf areas, the cover of which includes thin oil shale deposits (a metre or so to a few tens of metres thick). Most of these deposits are poor in oil product, yielding on average less than 114 litres (30 gallons) of oil per tonne (Duncan, 1976). The platform oil shale deposits are mostly of the siliceous type. However, there are carbonate-rich oil shales as well, of similar environmental origin. Most of higher-grade shales are of this type.

Oil shales on continental shelves include deposits formed in subsiding ocean basins, developed as a result of upwelling of nutrient-rich waters (as observed in modern seas along the western coast of the continents and certain other environments) on to a shoaling bottom. Like the platform deposits, most of the oil shales in this type of basin are of the siliceous type, but some are calcareous.

The platform shales are generally associated with limestone, quartz sandstone, and chert or cherty limestone; phosphate nodules are also a common associate. The oil shales themselves are generally dark brown or black shales associated with limestone, phosphate rock, sandstone, and chert, in assemblages much thicker than the platform type. Examples of this type of oil shales are the widespread black shales of Cambrian age in northern Siberia and northern Europe; Devonian age in eastern and central North America; Permian age in southern Brazil, Uruguay, and Argentina; and Jurassic age in Europe, eastern Asia, and Alaska. The Miocene shales of Sicily, Italy, and California have also maintained a sufficient potential to be classified among the richer oil shales, despite advancing metamorphism or maturation.

Among the typical characteristics of the various types of oil shale is a very fine lamination, made up of thin (less than 1 mm) alternating layers of organic matter and minerals. This lamination indicates tranquil sedimentation, where the minerals were either precipitated from solution (carbonates) or transported as very fine detritus (clay, minerals, silt). It suggests a succession of seasonal or other periodic events. Lamination also proves the absence of benthos. A situation of this kind represents a confined physicochemical environment, where the decay of part of the organic matter uses up oxygen to produce CO2. Thus organic matter is preserved from reworking by benthic fauna and from aerobic microbial degradation (Cane, 1976).

The organic content of lake deposits is extremely variable; it depends, for example, on the nutrient supply from the inflowing rivers, water circulation in the lake, and the stability of the water stratification (Taylor et al, 1998).

1.5. An Example of an Oil Shale Deposit

One of the well-known oil shale deposits in the world is the Green River Formation oil shales of Eocene age in Colorado, Wyoming and Utah (Duncan, 1976).

Oil yields ranging from 38 litres per tonne to 550 litres per tonne have been recorded from a range of rocks – limestones, marlstones, shales, siltstones and impure coals – all of which are collectively referred to as oil shales. The Scottish Lower Carboniferous oil shales, which are predominantly true shales, yield on average 90 litres per tonne, whereas the Green River Formation oil shales yield on average 125 litres per tonne (Yen and Chilingarian, 1976).

1.6. Indonesian Oil Shale Deposits

Oil shale studies have been carried out in Indonesia since the 1980s. However, since Indonesia has a greater abundance of oil, gas and coal resources, exploration to date has been more focused on these resources instead. Therefore, the Indonesian oil shales have been little studied and are poorly understood. Nevertheless, the Indonesian government is now trying to investigate alternative energy resources, and has been

19 intensively exploring its oil shale resources since the year 2000. Oil shale exploration is expected to continue as a long-term project in the next five years. It is expected that this research will provide significant contributions to the understanding of oil shale deposits in Indonesia, as well as adding to the nation’s energy resource base.

Before 2000, several researchers investigated the oil shales of Indonesia for scientific purposes, rather than for economic purposes. Hutton (1982) studied some oil shale samples from several countries including a sample from central Sumatra. He concluded that the oil shale sample from central Sumatra can be classified as lamosite, with characteristics close to the Rundle oil shale type.

Some of the main oil shale occurrences in Indonesia are in the Ombilin Basin and the Central Sumatra Basin, the location and geological setting of which are discussed more fully in Chapter 2. Several authors, including Ilyas (2000) and Tobing (2001), have described geological studies in these areas, and concluded that the main oil shale bearing formation of both basins is the Eocene Sangkarewang Formation.

Hutabarat et al. (1982) reported that the oil yields of shales from the Sipang River area in the Ombilin Basin decrease from the bottom part to the upper part of the Sangkarewang Formation. This trend is similar to that shown by oil yields in the Sumpahan River area, also in the Ombilin Basin. The upper part of the Sangkarewang Formation comprises oil shale intercalated with thin laminated sandstone. The oil shale is dark brown in color, thinly laminated and soft. The sandstone units are calcareous, and are characterized by a greenish grey colour with graded bedding and slump structures.

Oil shale deposits also can be found in other parts of Indonesia, such as Java, Sulawesi and Molucca, as well as Papua Island (previously called Irian Jaya). Some of these deposits are dispersed over vast areas but some of them only found as lenses (Tobing, 2002; Triono, 2002, Cahyono 2003). The Indonesia government plans to continue detailed oil shale exploration in the next couple years, which will add to the knowledge of these basins as well.

20 1.7. Objectives of the Present Study

The Ombilin Basin represents a reference section for sedimentation in the Lower Tertiary of Sumatra. Its exposures and accessibility has allowed it to be the subject of significant geological study for a long period of time (de Smet, 1991).

The objective of the present research project was to extend the understanding of the Ombilin Basin oil shales by investigating the relationship between the nature of the basin sediments, the organic matter and the oil yield in the main oil shale bearing succession. It is expected that this study will strengthen understanding of the geological framework for future exploration programs. Investigation for present study has indicated that the oil shale deposits are more concentrated in the Talawi area, in the southern part of the Ombilin Basin. Therefore, the present research has focused on the oil shale deposits of the Talawi area, which lies on the centre of the basin.

21 CHAPTER 2

GEOLOGICAL SETTING OF THE OMBILIN BASIN

2.1. Regional Setting

The geology of the Ombilin Basin has been an object of interest for a long time. The basin is well known for its economic coal deposits, which led to the first geological mapping of parts of the area as early as the 1870s. Later on, some work was also carried out for petroleum exploration purposes.

Koesoemadinata and Matasak (1981), Koning (1985), Daulay and Cook (1988), de Smet (1991), Williams et al. (1995), Moss and Carter (1996), Moss and Howells (1996), Hutabarat et al. (1982), Suwarna et al. (2001), and Ilyas (2001) have presented overviews of the Ombilin Basin. Some of these authors investigated the area for coal exploration purposes, whereas others carried out studies for petroleum exploration. Only a few have focused on oil shale exploration in the area.

The Ombilin Basin is located on the crest of the Barisan Mountain Range of West Sumatra, Indonesia (Figure 2.1). Its present day geomorphological position reflects its origin as an intermontane basin resulting from Plio-Pleistocene uplift of the Barisan Mountains. The basin is a relatively small Tertiary basin, covering an area approximately 25 km wide and 60 km long, trending parallel to the main axis of Sumatra (de Smet, 1991). The original basin was probably considerably larger than the present basin outline, and post depositional erosion has probably removed much of the peripheral area of the original basin.

Koning (1985) described the Ombilin Basin as a remnant pocket of Tertiary sediment, which originally extended over much of the present Barisan Mountains. The total amount of sedimentary section deposited within the Ombilin Basin may have exceeded 9,200 m (30,000 ft).

22 Figure 2.1. Outline map of Sumatra, showing the location and extent of the Ombilin Basin (de Smet, 1991)

23 The eastern side of the basin is bounded by the Takung Fault (Figure 2.2), in which pre-Tertiary rocks are thrust over the Tertiary sediments. The basin deepens abruptly on the western side of the Takung Fault, where the Tertiary section is downthrown against several northwest-southeast trending reverse faults (Figure 2.3). These faults may also have associated lateral movement.

The southern boundary of the basin is not fault-bounded. The southeastern half of the basin was uplifted by a post-middle Miocene orogeny, followed by erosional truncation of the Tertiary formations, to establish the present southern and western margins.

The north-south trending Tanjung Ampalo Fault (Figure 2.2) bisects the Ombilin Basin. This fault structure formed a prominent scarp, which separated the deeper part of the Ombilin Basin from the Sigalut Plateau to the northwest. The Tanjung Ampalo Fault is believed to be a second order dextral wrench fault, formed in response to first order dextral strike-slip stress associated with the Great Sumatra Fault Zone (Koning, 1985). The fault bifurcates in the south, with one strand striking south of the basin into the pre- Tertiary highlands and the other paralleling the western margin of the basin.

Basin uplift and complex faulting both control the western margin of the basin. The magnitude of the basin margin tectonics is evident at the southern entrance to the town of Sawahlunto, where several thousand metres of Tertiary sediments can be seen juxtaposed against the Triassic limestones of the basement (Koning, 1985).

The northern part of the basin is divided into eastern and western segments, separated by a prominent ridge of basement outcrops at the Bukit Tungkar Ridge (Figure 2.2). The eastern extension (the “North Limb”) of the basin narrows to a width of only 4 to 5 km, and continues northward to disappear beneath the recently extinct Malintang volcano (Gunung Malintang, Figure 2.2). Although the North Limb is a very narrow trough, flanked on both sides by pre-Tertiary basement highlands, the Tertiary sediments are little deformed and dip gently to the north - west.

24 Figure 2.2. Geologic map of the Ombilin Basin (Koesoemadinata and Matasak, 1981)

25 A second northern extension of the Ombilin Basin is the Talawi Syncline (Figure 2.2), located southwest of the Bukit Tungkar Ridge. This is a northwest – southeast trending syncline containing a thin section of Tertiary sediments.

The Talawi area (Figure 2.2) was extensively uplifted, and subsequent erosion has left only a thin veneer of Tertiary section. The Talawi Syncline extends from the Sigalut Plateau northwestwards towards Batusangkar, where the Tertiary sediments are masked by volcanic debris, which flowed down the flanks of the presently active Marapi volcano (Gunung Marapi, Figure 2.2).

The southern part of the Ombilin Basin contains the Palangki Anticline (Figure 2.2). This major structural element is a horst resulting from basement block faulting, and is expressed topographically as a prominent “nose” rising approximately 400 m (1,300 ft) above the adjacent basin plain. At the south end of the Palangki Anticline uplift and subsequent erosion have exposed pre-Tertiary andesites at the surface in the core of the anticline (Figure 2.4).

Figures 2.3 and 2.4 illustrate geologic cross section of the Ombilin Basin through the northern and southern parts of the basin.

2.2. Tectonic Setting

Sumatra Island, one of the five major islands in Indonesia, is located in the western part of Indonesia. Tectonically, this island lies on the magmatic arc in the tectonic setting of Indonesia (Figure 2.5). More detail of the tectonic setting of Sumatra can be seen in Figure 2.6. According to Katili and Hehuwat (1967), there are two distinctive and intimately related tectonic features that dominate the geology of West Sumatra, namely the magmatic arc and the Great Sumatra Fault System.

26 Figure 2.3. Idealised geologic cross section through the northern part of the Ombilin Basin (Koesoemadinata and Matasak, 1981)

27 Figure 2.4. Idealised geologic cross-section through the southern part of the Ombilin Basin (Koesoemadinata and Matasak, 1981) 28 Figure 2.5. Tectonic setting of Indonesia (Koesoemadinata and Matasak, 1981)

29 Figure 2.6. Tectonic setting of Sumatra (Koesoemadinata and Matasak, 1981)

The structural evolution of the Ombilin Basin is related to the Great Sumatra Fault system. However, its evolution until the end of the Miocene was related to the same tensional tectonic regime that formed the Central Sumatra Basin. The Ombilin Basin was separated from the Central Sumatra Basin by the mountain ranges that formed as a result of post – Early Miocene uplift (Figure 2.7), which was related in turn to the Sumatra Fault System (Koning, 1985). The present structure of the Ombilin Basin

30 is dominated and strongly overprinted by the Great Sumatra Fault System (Figure 2.2), and is largely Plio-Pleistocene in age.

The Great Sumatra Fault zone is active. Evidence of present day lateral movement can be seen from stream offsets and road dislocations along the main fault and some its splays. The 1926, 1943 and 1983 earthquakes in the Padang Panjang area (Figure 2.2) testify to the area’s seismicity (Koning, 1985). PT Caltex Pacific Indonesia carried out a side-looking radar survey of the Singkarak Block with synthetic aperture radar (SAR) in October 1981. Koning (1985) observed that the Great Sumatra Fault is recognizable on the SAR imagery within the Singkarak Block as a single continuous fault trace extending northwest from Lake Singkarak for some 60 km (Figure 2.2). Marked dislocation of Recent water-lain volcanic debris and alluvium from the Marapi volcano (Figure 2.2) provides evidence of present day motion along this fault.

Numerous graben-like structures, including Lake Singkarak, can be recognized along the length of the Great Sumatra Fault Zone. According to Van Bemmelen (1949), these structures resulted from uplift of the “Barisan Geanticline” and longitudinal median depressions formed by associated tensional stresses and block faulting. The occurrence of Paleogene basins, such as the Ombilin Basin, within the Barisan Mountains indicates an Eocene age for graben development. Katili and Hehuwat (1967) contend that Middle Cretaceous to Early Tertiary orogenesis was responsible for graben formation, and that transcurrent tectonics were not active until the Early Pleistocene. Koning (1985) believed that the Ombilin Basin is a graben-like, pull-apart structure resulting from Early Tertiary tensional tectonics related to strike-slip movement along the Great Sumatra Fault Zone.

2.3. Stratigraphy The Ombilin Basin and surrounding area contain a wide variety of rock units, from pre-Tertiary to Quaternary in age. The pre-Tertiary rock units acted as a basement for the Tertiary rocks of the basin. Several authors have discussed the stratigraphic nomenclature of the rock units in the Ombilin Basin (eg. Musper, 1929; Marks, 1946;

31 Van Bemmelen, 1949; Kastowo and Silitonga, 1973; Koesoemadinata and Matasak, 1981).

Musper (1929) described a comprehensive stratigraphy for the northern half of the Ombilin Basin. Unfortunately, his report was written in Dutch and, for this reason, not many people refer to his stratigraphic nomenclature. Marks (1946) has written the stratigraphic lexicon of Indonesia and described an overview of the rock units in the Ombilin Basin. Similarly, Van Bemmelen (1949) described a general overview of the Ombilin Basin in his work on the geology of Indonesia.

The detailed stratigraphy of the Ombilin Basin was also described by Kastowo and Silitonga (1973) in part of their work on the geology of the Solok Quadrangle. However, according to Koesoemadinata and Matasak (1981), some of the stratigraphic nomenclature of the Ombilin Basin, especially the Tertiary units, had to be updated to follow the Stratigraphic Code of Indonesia. Accordingly, Koesoemadinata and Matasak (1981) proposed a detailed stratigraphy of the Tertiary units of the Ombilin Basin, complete with the type section and type localities of each unit.

In the Geology of the Solok Quadrangle, Kastowo and Silitonga (1973) divided the Tertiary units of the Ombilin Basin into the Brani Formation, the Sangkarewang Formation and the Ombilin Formation, with the latter subdivided into the Lower Ombilin and the Upper Ombilin. Koesoemadinata and Matasak (1981) updated this information by defining the Lower Ombilin as a separate unit, the Sawahtambang Formation. The Upper Ombilin of Silitonga and Kastowo (1973) remained as the Ombilin Formation. Koesoemadinata and Matasak (1981) have presented an excellent work on the detailed stratigraphic units of the Ombilin Basin. Other authors have also discussed the stratigraphic units of the Ombilin Basin (eg. Koning, 1985; De Smet, 1991), as summarised in Figure 2.8. All have generally have confirmed the stratigraphic nomenclature of Koesoemadinata and Matasak (1981). The stratigraphy of the Ombilin Basin, based on the stratigraphic nomenclature of Koesoemadinata and Matasak (1981), is summarised below.

32 Figure 2.7. Diagrammatic cross-section across Central Sumatra showing the tectonic setting of the Ombilin Basin (Koesoemadinata and Matasak, 1981)

33 Figure 2.8. Stratrigraphic sequence in the Ombilin Basin as defined by different authors (de Smet, 1991) 34 2.3.1. Pre-Tertiary Rocks

The pre-Tertiary sediments and metasediments surrounding the Ombilin Basin are of Paleozoic and Permo-Triassic age. De Smet (1991) observed three pre-Tertiary rock units exposed in the Ombilin Basin area, namely the Kuantan Formation, the Silungkang Formation and the Tuhur Formation. These rocks are well exposed around the basin margin. The Ombilin Basin is surrounded to the north, east and south by Permo-Carboniferous metasediments (part of the Kuantan Formation), and large intrusions of granitic rocks. Permo-Carboniferous slates and phyllites of the Kuantan Formation crop out along the eastern margin of the basin and a limestone member of this formation is exposed on the southeast margin of the basin. A complex assemblage of pre-Tertiary rocks is exposed along the western margin. These include Permo- Carboniferous and Triassic limestones, slates and volcanics, and the Middle Cretaceous Lassi Granite (Katili, 1962 in Koning, 1985). Permian limestones crop out close to the eastern shore of Lake Singkarak.

The Kuantan Formation can be subdivided into three members (de Smet, 1991): - The “Lower Member”, which consists mainly of reddish to dark brown shale and phyllite, contains thin intercalation of dark-grey slate, quartzite, siltstone and some chert. The total thickness of this member is 1,000 m. - The middle part of the Kuantan Formation is known as the “Limestone Member”. It consists of massive limestone and marble with thin intercalations of slate, phyllite and quartzite. The outcrop of this member, which forms an impressive, inaccessible, karsted landscape with caves and springs, borders the eastern side of the Ombilin Basin. The stratigraphic thickness of the member in this area is 500 m. - The Upper Member consists of quartzite and quartz sandstone, mainly brown in color, and contains intercalations of phyllite, siliceous slate, volcanic rock, tuff, conglomerate and brown chert. The total thickness of this member may be several kilometres.

To the west of the Ombilin Basin the pre-Tertiary sequence includes large outcrops of volcanic and volcano-clastic deposits, and also well bedded and far less metamorphosed sandstones and limestones. These strata belong to the Permian

35 Silungkang Formation and the Triassic Tuhur Formation. De Smet (1991) gives a detailed account of these formations, summarised below.

The lower part of the Silungkang Formation consists mostly of hornblende andesite, augite andesite and meta-andesite, with thin intercalations of tuff, limestone, shale and sandstone mixed with tuffaceous material. The upper part consists of limestone and calcareous sandstone, with a few intercalations of agglomerate tuff and several flows of augite andesite and basalt. The total thickness of the Silungkang Formation is 1,500 m.

Massive, bluish grey limestones, with thin intercalations of shale, sandstone and tuff, make up the limestone member of the Silungkang Formation. It is believed that this member is Permian in age.

The limestone member of the Tuhur Formation, which overlies the Silungkang Formation, consists of poorly bedded, sandy limestones and massive fossiliferous conglomeratic limestones containing pebbles of Permian, fusulinid bearing beds.

The pre-Tertiary basement contains large intrusions, which consist of granite, granodiorite, quartz diorite and quartz porphyry. Radiometric dating has revealed ages ranging from Late Permian to Quaternary, but mainly indicate a Late Jurassic or Early Cretaceous origin.

The Tungkar High, which divides the northern part of the Ombilin Basin into a western and an eastern segment, consists of granite and quartz porphyry. Calcite veins are rather common in the granites. The granites provided the source of breccias and coarse, angular sandstones that form the base of the Tertiary stratigraphic succession, and also interfinger with the lake deposits of the Sangkarewang Formation.

36 2.3.2. Tertiary Rocks

The Tertiary stratigraphy of the Ombilin Basin comprises a late Eocene/early Oligocene initial basin fill of marginal fans and lacustrine shales (Sangkarewang Formation), overlain by a late Oligocene/early Miocene fluvial sequence (Sawahlunto and Sawahtambang Formations), and capped by an early to mid-Miocene marine sequence (Ombilin Formation). Within the Ombilin Basin the initial basin fill sequence (Sangkarewang Formation) is separated from the subsequent fluvial sequence (Sawahlunto Formation) by an angular unconformity.

As indicated in Figure 2.8, Koesoemadinata and Matasak (1981) subdivided the Tertiary deposits of the Ombilin Basin into five formations, namely: - Ombilin Formation (Early Miocene) - Sawahtambang Formation (Oligocene) - Sawahlunto Formation (Late Eocene) - Sangkarewang Formation (Paleocene-Eocene?) - Brani Formation (Paleocene-Eocene?)

The outcrop distribution of these units is also shown in Figure 2.2. The Tertiary stratigraphic sequence of the Ombilin Basin is described more fully as follows:

Brani Formation

The Brani Formation is characterized by a sequence of purple brown rusty looking polymict pebble to cobble conglomerates with a muddy sand matrix. The sediments are very poorly sorted, subangular to subrounded, dense, hard to friable, and generally non-bedded to occasionally poorly bedded (Koesoemadinata and Matasak, 1981). The composition of the pebble components varies, depending on the basement rock over which they were deposited, and reflects the short distance of transportation involved. On the western rim of the basin they consist of volcanic rock (andesite), limestone (fusulinids occur occasionally), slate and argillite pebbles. Granite pebbles predominate on the eastern rim, along with quartzite and milky quartz pebbles. Coarse arkosic grits occur occasionally. Bedding is typically absent or crudely developed. De

37 Smet (1991) believed that the breccias and coarse, angular sandstones were derived from the pre-Tertiary granites surrounding the area.

The Brani Formation is widely distributed along the rim of the Ombilin Basin, as well as in the core of the Palangki Anticline in the southern part of the basin. It is well exposed in the northwestern part of the basin. The thickness of the formation ranges from more than 646 m to practically nil as it pinches out in certain directions (Koesoemadinata and Matasak, 1981).

Koesoemadinata and Matasak (1981) distinguished two members of the Brani Formation in parts of the area: the Kulampi Member and the Selo Member. The Kulampi Member has all the characteristics of the Brani Formation, but the conglomerate beds are typically interbedded with poorly sorted sandstones, forming a graded cyclic sequence. However, bedding is poorly developed. The Selo Member can be separated from the rest of the Brani Formation by the absence of the typical rusty violet brown color. All the conglomerate fragments are granite, 8 to 75 cm in diameter. The matrix is of sand-size material, poorly sorted, subangular to subrounded, medium to coarse grained, and argillaceous with a calcareous cement. The member is mostly distributed in the northwestern part of the basin. De Smet (1991) preferred not to distinguish a “Brani Formation” at all, and identified a large number of members that could potentially be added to the list.

According to Koesoemadinata and Matasak (1981) the stratigraphic position of the Brani Formation is “occasionally below or above the Sangkarewang Formation”, and “the Brani Formation is conformably overlain by the Sawahlunto Formation, with a gradational interfingering relationship in the western rim of the basin” (see Figure 2.3). From his observations de Smet (1991) concluded that the stratigraphic position of the Brani Formation sediments could vary in several different locations. It typically shows a normal stratigraphic position below and beside the Sangkarewang Formation, but has an unconformable contact at locations where it apparently overlies the Sangkarewang Formation. The contact is a normal stratigraphic contact, however, where it occurs below the Oligocene Sawahtambang Formation (Figure 2.3).

38 De Smet (1991) contends that the sedimentary environment of the Brani Formation is variable. The strata were formed partially as alluvial fan and partially as coastal deposits. Some were subaerially exposed and some were deposited as turbidites. Koesoemadinata and Matasak (1981) considered the Brani Formation to be an alluvial fan deposit. The Selo Member reflects the fanhead portion of the alluvial fan, whilst the Kulampi Member represents a more distal part. Van Bemmelen (1949) suggested that the variegated and coarse nature of the Brani conglomerates and their restricted distribution indicate that the conglomerates are local deposits formed in intermontane basins within an Eocene mountain range.

Sangkarewang Formation

The name “Sangkarewang” is based on the type locality of the unit in the Sangkarewang River, near Sawahlunto town (Figure 2.2). According to Koesoemadinata and Matasak (1981), the Sangkarewang Formation consists of laminated shales with dark bluish grey to black color, that weather to a yellowish brown. The shales are typically plastic and papery and are locally calcareous, but also contain carbonaceous material with mica, pyrite and plant remains. Intercalation of turbidite sandstone is common. The sandstones are quartz to feldspar-bearing, calcareous, and grey to black in color. They typically show fining upward sequences. They are poorly sorted, with an argillaceous matrix, and contain mica and carbonaceous material. Slump structures are prevalent in the formation and can be considered as typical. Plant remains often preserved on the lamination planes (de Smet, 1991).

The Sangkarewang Formation is spread over almost the entire northwestern part of the basin. Small patches occur elsewhere. According to Koning (1985) the formation extends underneath the larger part of the basin.

The Sangkarewang Formation is renowned for the occurrence of well preserved, fresh water fish fossils Musperia radiata (Herr) and Scleropagus (Koesoemadinata and Matasak, 1981; Koning, 1985). According to Koning (1985), an extraordinarily well preserved skeleton of the bird Protoplotus beauforti was also exposed in the Sangkarewang Formation. This fossil is paleoenvironmentally significant because it

39 represents the oldest evidence of relatives of the living snake bird or darter, which are birds restricted primarily to the wet tropics today (Rich and Marino – Hadiwardoyo, 1977).

Suwarna et al (2001) carried out a palynological study of the oil shale from the Ombilin Basin and found that Florschuetzia trilobata, Verrucatosporites usmensis, Cicatricosisporites dorogensis, Palmaepollenites kutchensis, Polyad pollen, Laevigatosporites, Dicolpopolis malesianus, and Crassoretitriletes vanraadshooveni were present in the shale and mudstone samples of the Sangkarewang Formation. These palynomorphs represent a Middle Eocene to Oligocene age. However, there is no explanation on the significance of this extension to Oligocene.

The stratigraphic relationship of the Sangkarewang Formation varies at different localities. The Sangkarewang Formation unconformably overlies the pre-Tertiary basement rocks, and is conformably overlain by the Sawahlunto Formation. It shows an interfingering relationship with a tongue of the Brani Formation, which separates the Sangkarewang Formation from the pre-Tertiary beds as well as from the overlying Sawahlunto Formation. A lateral interfingering relationship with the Brani Formation is rather well recognized. The Sangkarewang Formation may be considered as either a lens within the Brani Formation or as an interfingering unit with the Sawahlunto Formation (Koesoemadinata and Matasak, 1981). The upper boundary of the Sangkarewang Formation is represented by a high angle unconformity, and is followed in the stratigraphic succession by sandstones of the Sawahlunto or Sawahtambang Formations.

Koning (1985) has studied the petroleum geology of the Ombilin Basin based on data from the Sinamar No. 1 well (well location in Figure 2.2). Sinamar No. 1 is a significant well in the history of Indonesia’s oil industry. It was the first exploratory well drilled for hydrocarbons in an intermontane basin in Indonesia. It also represents the first oil and gas exploratory drilling in the West Sumatra province. In his study, Koning reported the presence of a significant intra-Sangkarewang unconformity at 2,700 m (8,840 ft) in Sinamar No. 1, indicated by a marked shift in vitrinite reflectance and spore color index (Figure 2.9). De Smet (1991) assumed that this unconformity was

40 possibly present only in the deeper central parts of the basin and not in the marginal areas. In this case, the top part of the Sangkarewang Formation, as reported by Koning, could be represented in the hiatus at the unconformity below the Sawahlunto Formation. Alternatively, the lower part of the Sangkarewang Formation was never deposited in the marginal areas of the basin. Such an unconformity, if present, would be hard to detect in the field as a consequence of the slumping phenomena found in almost all outcrops.

This shifted vitrinite reflectance, however, may not necessarily represent an unconformity. Figure 2.9 indicates that the spore colour index profile tends to increase with depth while the vitrinite reflectance shows suppressed values in the intra- Sangkarewang “unconformity”. Such suppression may be caused by the abundance of liptinite in the vitrinite-poor source rock (see Chapter 4) as well as by lithology or by marine influence. As mentioned, the Sangkarewang Formation is composed of shale, which can give a lower reflectance value than coal due to thermal conductivity effects (Mukhopadhyay, 1994). The vitrinite reflectance suppression cannot be determined precisely due to lack of information of the actual vitrinite reflectance values on the profile in Figure 2.9. The Sangkarewang Formation boundary is also not clear in this figure.

Like Koning (1985), Williams et al. (1995) contend that the stratigraphic contact between the upper and the lower parts of the Sangkarewang Formation is an unconformity. Such unconformities are also present at the base of the Sangkarewang Formation, as well as at the top of the Sangkarewang Formation.

The Sangkarewang Formation was deposited in a stable lacustrine environment with euxinic conditions (Koesoemadinata and Matasak, 1981; Koning, 1985; de Smet, 1991). According to Koning (1985), reconstruction of the outcrop data outlines a large lake covering at least 1,000 sq km. By way of comparison, the ancient “Lake Sangkarewang” interpreted from these data covered an area approximately ten times larger than the present Lake Singkarak on the western side of the basin (Figure 2.2). However, the Sangkarewang lake is small compared to the Eocene Green River Formation’s Lake Gosiute, which extended over 50,000 sq km in Wyoming and Colorado (Picard and High, 1972 in Koning, 1985). From his observations, de Smet

41 (1991) postulated that, in Sawahtambang time, the northwestern and southern borders of the lake were close to the present borders of the basin. At the eastern side of the basin, however, the lake may have extended beyond the present basin boundary.

Williams et al (1995) suggested that the lower part of the Sangkarewang Formation was deposited in a shallow lacustrine milieu whilst the upper part of the formation was deposited in deep lacustrine conditions. The lower Sangkarewang appears to represent the transition from a basal rift-fill to the dark brown to black, organic-rich lacustrine shales of the upper Sangkarewang Formation. The lower Sangkarewang Formation consists dominantly of dark silty shales with minor variously coloured shales and interbedded thin sandstones. The lacustrine phase of the rift-fill sequence is represented by 358m of dark brown, fissile, calcareous to non-calcareous organic-rich shale of the upper Sangkarewang Formation, deposited in deep anoxic lake conditions. Unconformities at the base and top of the Sangkarewang Formation reflect and emphasize the tectonic control on sedimentation. A phase of tectonism, with rapid graben subsidence, initiated the development of deep lake conditions, followed by a long period of quiescence and organic-rich shale accumulation.

Suwarna et al. (2001) found that the pollen and spore fossils of the Sangkarewang Formation are dominated by freshwater affinities, comprising Florschuetzia trilobata, Marginipollis type, Palmaepollenites kutchensis, Palmae, Dicolpopollis malesianus, and Polyad pollen; and Pteridophyte spore composed of Magnastriatites howardii, Crassoretitriletes vanraadshooveni, Cicatricosisporites dorogensis, Laevigatosporites, Triletesporites, Verrucatosisporites usmensis, and Verrucosisporites. They also observed some tidal (back-mangrove/mangrove) palynomorphs, such as Zonocostites ramonae, Acrosthicum aureum and Discoidites borneensis. From the assemblage of these palynomorphs they interpreted the depositional environment of the Sangkarewang Formation as an alluvial or freshwater swamp influenced by a marine incursion.

42 Figure 2.9. Vitrinite reflectance values and spore colour index profiles from Sinamar No.1 (Koning, 1985)

43 Sawahlunto Formation

The Sawahlunto Formation consists of Eocene shale, siltstone, quartz sandstone and coal, occurring mostly in the northeastern part of the basin (Koesoemadinata and Matasak, 1981). Coal beds of this formation are mined at Sawahlunto. The sediments do not contain any fossils except for plant remains and some benthonic foraminifera (de Smet, 1991). According to Koesoemadinata and Matasak (1981), the Sawahlunto Formation wedges out to the east and south of the Sawahlunto area.

Koesemadinata and Matasak (referring to a JICA 1979 report) considered a Palaeocene age for the Sawahlunto Formation, based on the presence of Proxapertites operculatus. Nevertheless, since the number of these microfossils is very small, an Eocene age may also be a possibility. Florschetzia, an index fossil for the post-Eocene in Southeast Asia, has not been detected.

Bartram and Nughrahaningsih (1990) have done a palynological study of the Sawahlunto Formation. They reported an ‘Oligocene to Miocene rather than Eocene’ age for the Sawahlunto Formation.

Considering the similarities origin between the Ombilin Basin and the backarc basins of Sumatra, de Smet (1991) interpreted a late Eocene to Oligocene age for the Sawahlunto Formation.

Koesoemadinata and Matasak (1981) concluded that the lower contact of the Sawahlunto Formation is gradational and conformable with the Brani Formation. De Smet (1991) made an interesting note about the stratigraphic position of the Sawahlunto Formation. He distinguished the lower contact of the Sawahlunto Formation locally by the presence of basal breccias of the Brani Formation. He noted that “basal breccias are found locally in a conformable position underneath the Sawahlunto Formation. When one includes these breccias in the Brani Formation then the basal contact of the Sawahlunto is normal. However, where such breccias are missing, the basal contact of the Sawahlunto Formation is a high angle unconformity, and where the breccias occur, they are basal and still mark an unconformity”.

44 Koesoemadinata and Matasak (1981) as well as de Smet (1991) agreed that the upper contact of the Sawahlunto Formation is gradational into the Sawahtambang Formation. However, Koning (1985) identified a marked shift in vitrinite reflectance values at 2,130 m (7,000 ft) in Sinamar No. 1 (Figure 2.9), which was interpreted to indicate an unconformity between the Sawahlunto and Sawahtambang Formation. Instead of an unconformity hypothesis, this shifted reflectance value may be suppressed due to the vitrinite-poor (liptinite-rich) lithology of the organic matter in the Sawahtambang Formation. The stratigraphic column of the Sinamar No.1 well can be seen in Figure 2.10.

Based on the presence of carbonaceous shales, coals and especially point bar sandstones, Koesoemadinata and Matasak (1981) interpreted the Sawahlunto Formation as flood basin and meandering river deposit.

Sawahtambang Formation

According to Koesoemadinata and Matasak (1981), the Sawahtambang Formation consists of a thick massive sequence of cross bedded sandstones, mostly quartzose to feldspathic. The sandstones are light grey to brown, and fine to very coarse grained. They are poorly sorted and often conglomeratic. Shales and siltstones are locally developed. The Sawahtambang Formation can be distinguished from the Sawahlunto Formation by the presence of these conglomerates.

Koesoemadinata and Matasak (1981) identified two members of the Sawahtambang Formation, the Rasau Member in the lower part of the formation and the Poro Member in the upper part. The Rasau Member differs from the rest of the Sawahtambang Formation by the presence of hard and dense argillaceous siltstone (mudstone) intercalations, typically blue-grey but weathering to reddish brown in colour and containing carbonaceous material. No coal beds are developed in this member. The Poro Member differs from the Sawahtambang Formation by being non conglomeratic. It consists of a sequence of quartz sandstones, with frequent interbeds of grey shales and coal stringers and grey carbonaceous siltstones. The Sawahtambang Formation is distributed over the entire basin, but is mostly found along the basin flank. The Rasau

45 Member is distributed only in the southwest of the basin, whereas the Poro Member is particularly found in the western part of the basin.

Figure 2.10. Stratigraphic units of the Ombilin Basin in the Sinamar No. 1 well (Koning, 1985)

46 De Smet (1991) noted that the characteristics of the Rasau Member, which consists of poorly bedded, conglomeratic river deposits and which shows a purple brown vein-like network, are closer to the definition of the Brani Formation.

The total thickness of the formation varies from 90 m at the southern end of the basin to 2,440 m in the northern limb. However the original thickness may have been larger, considering that several thousands of metres of Sawahtambang beds were likely to have been removed during a late Oligocene – Early Miocene depositional hiatus (Koning, 1985).

Based on its stratigraphic position below the Ombilin Formation, which is definitely Early Miocene in age, and the fact that it occurs conformably on top of the Sawahtambang Formation, Koesemadinata and Matasak (1981) suggested that the Sawahtambang Formation is Oligocene in age.

The Oligocene conglomerates, sandstones and shales of the Sawahtambang Formation were deposited by a braided river system that flowed through a median alluvial valley. Toward the end of the nonmarine cycle, however, meandering streams and peat swamps developed locally and laid down thin coals and mudstones (Koesoemadinata and Matasak, 1981).

Ombilin Formation

The Early Miocene Ombilin Formation consists of light medium grey shales which are often calcareous and commonly contain limestone nodules, plant remains and mollusk shells. The Ombilin beds are exposed along several fault scarps on the western basin margin near Batumanjulur, revealing 60 m (200 ft) of coral rich, poorly bedded limestones. Similar Ombilin limestone beds are mapped near the eastern margin of the basin. The type section for the Ombilin Formation consists of approximately 1,460 m (4,800 ft) of sediments, and is located near Padang Lawas (Koesoemadinata and Matasak, 1981). Seismic data over the North Limb of the basin indicate the presence of approximately 2,740 m (9,000 ft) of Ombilin Formation (Koning, 1985). The true thickness of Ombilin beds originally deposited in the basin is unknown due to post-

47 depositional erosion. Tertiary sediments younger than Early Miocene, other than Recent volcanics, are not present in the basin, since rapid uplift of the Barisans prevented deposition of sediments younger than Early Miocene. Therefore the Barisans locally became the sediment source area for the Middle Miocene and younger rocks, such as the Pliocene Petani Formation of Central Sumatra. Erosion after this post Early Miocene uplift cut deeply into the pre-Tertiary terrain and the overlying veneer of Tertiary sediments, and reduced the Ombilin Basin to its present small but deep configuration.

2.4. Depositional History

The geological features of the rock units in the Ombilin Basin represent the history of the basin itself. This history started in the Early Tertiary, most probably in the Paleocene, when the Late Cretaceous orogeny followed by tensional stresses gave rise to block faulting. A graben-type intramontane basin was developed with steep fault escarpments at its sides, not much larger than the present basin outline. Alluvial fans developed at all sides of the basin, resulting in deposition of the Brani Formation conglomerates, of which the Selo Member represents the fan heads and the Kulampi Member represents the distal fans, where the conglomerates show some grading and bedding. A lake developed in the centre of the basin, presumably somewhat off-centre toward the northwestern part, where occasional turbidites were deposited. This lake is represented by the Sangkarewang Formation.

In Eocene time, the basin subsided and sedimentation continued, while erosion of the surrounding hills resulted into a lesser relief. An alluvial valley with a river system developed over the entire basin, except in the central and northeastern parts where the former lake became a swampy area with luxurious plant growth, forming a flood plain of meandering rivers. Sediments deposited in this swampy environment are represented by the coal seams of the Sawahlunto Formation. Sedimentation continued and the swampy area dried up to become a flood plain of meandering rivers. The surrounding hills were subjected to renewed uplift and coarser sediments were deposited, such as conglomeratic sandstones, still in point-bars, forming the Rasau Member of the Sawahtambang Formation. Sedimentation continued in Oligocene time,

48 with continuing uplift and subsidence resulting in the development of an alluvial valley with a braided river system, represented by the conglomeratic sandstone sequences of the Sawahtambang Formation in which thin coal beds and shale interbeds are common.

Toward the end of Oligocene time some local uplift took place, resulting in an erosional surface at Palangki. In Early Miocene time the whole region subsided and a marine transgression took place. The whole area changed immediately to a neritic to bathyal environment, represented by the Early Miocene calcareous shales and limestone lenses of the Ombilin Formation. Some volcanic activity took place in the nearby area, resulting in tuffaceous intercalations in the upper part of the Ombilin Formation. The presence of Miocene intrusives in the northeastern part of the basin also indicates magmatic activity at this time. Miocene sedimentation was not only confined to the basin, but covered the whole region. Early Miocene sediments are known to lie directly on pre-Tertiary rocks, such as at Lipat Kain, in the eastern part of the Barisan Range.

The historical record of the rest of the Miocene and Pliocene is missing, but apparently folding and faulting took place in Plio-Pleistocene time, when the whole Barisan Range was uplifted with subsequent erosion and deposition of Pleistocene tuffs of the Ranau Formation, and the present geological picture of the area emerged.

2.5. Previous Work on Ombilin Basin Oil Shales

Studies of the lacustrine deposits of the Ombilin Basin, particularly the oil shale deposits, have been carried out by several authors over the past 25 years (e.g. Hutabarat et al, 1982; Williams et al, 1995; Moss and Carter, 1996, Ilyas, 2000; Suwarna et al, 2001).

Hutabarat et al. (1982) noted a few oil shale outcrops in the Ombilin area. From this preliminary study they reported that the oil shale deposits in the Ombilin area yield between 0.15 and 3.91% wt of oil, and that the yield tends to decrease from the bottom to the upper part of the Sangkarewang Formation.

49 The Sangkarewang lacustrine shales in the Sinamar-1 well have an average TOC content of 2.64 wt %, with a range from 1.95 to 4.98 %. Pyrolysis HI vs Tmax plots indicate that the Sangkarewang in that area is at an advanced stage of maturity (gas / condensate window), and has expended most of its generative potential (Koning, 1985).

The Ombilin Basin contains two oil seeps (Figure 2.2). The oil from the Batikin seep has a gravity of 23o API and a pour point of 35oF. The oil from the Kolok seep has a gravity of 23o API and a pour point of 30oF. Both oils are biodegraded. The hydrocarbons tested from Sinamar No. 1 and the oil seeps in the Ombilin Basin were apparently sourced from either the Sangkarewang lacustrine shales or from sporadic intervals of organic-rich shales and mudstones within the Sawahtambang and Sawahlunto Formation.

Williams et al. (1995) studied the characteristics of some lacustrine basins in southeast Asia including the Ombilin Basin. This study briefly discussed the lacustrine deposit characteristics of the Ombilin Basin, i.e. the Sangkarewang Formation sediments. The average of total organic carbon content from outcrop samples of the Sangkarewang Formation is 7.2 wt % (range 1.66 – 18.7 wt %). Rock Eval pyrolysis indicates high HI values, characteristic of algal-rich oil prone source rocks, with average S2 values of 42.3 mg HC/g rock (range 3.9 – 87.8). Microscopic kerogen analysis confirmed a dominance of algal and amorphous kerogen. Extract hydrocarbon contents of the surface samples varied from 760 to 9,310 ppm, with HC: TOC ratios of 0.7 – 6.4. Gas chromatograms of the outcrop extracts show three distinct groupings (identified as A, B and C in Figure 2.10), which represent separate organic facies. Rock Eval pyrolysis HI values and microscopic kerogen analyses show a strong algal input in all three facies, with no significant terrestrial input. These samples illustrate the variability of the lacustrine source sequence in the marginal setting. Pristane:phytane ratios for all three facies range from 1.80 to 5.96, suggesting deposition in mildly to strongly oxidizing environments.

Williams et al. (1995) concluded that the lacustrine shales of the Ombilin Basin were dominantly deposited in a deep anoxic? fresh water lake environment. However, shallow water facies were developed in marginal basin settings. The anoxic lacustrine

50 shales of the Sangkarewang Formation represent deposition in an increasingly deepening lake. The final stages of shale deposition, however, were in a shallowing lake represented by the Sawahlunto coals deposited in extensive swamps later in the succession.

Figure 2.11. Typical saturate fraction gas chromatograms derived from outcrop samples of the Sangkarewang Formation (Williams et al, 1995)

51 Moss and Carter (1996) studied the thermal history of the Ombilin Basin using organic petrography and apatite fission track data. They reported that vitrinite reflectance values in the Ombilin Basin range from 0.39% to 0.89%. The vitrinite reflectance values were calculated from several samples including Sangkarewang shale and siltstone and Sawahlunto coal samples. An interesting point of this report is that the lowest reflectance value was obtained from a Sangkarewang shale sample, while the highest value came from the Poro Member of the Sawahtambang Formation. According to the stratigraphy of the Ombilin Basin, the Sangkarewang Formation is older than the Sawahtambang Formation. However, the reflectance values obtained by Moss and Carter (1996) do not reflect this stratigraphic relationship. Normally, older rock units would be expected to have higher reflectance values (Hilt’s law). The authors gave no explanation for the anomalous trend, although it is addressed elsewhere in the present study.

Ilyas (2000) reported that the vitrinite reflectance of the oil shale deposit in the Talawi area ranges between 0.19% and 0.51%. Lamalginite content is about 20% to 40%. Ilyas (2000) also suggested that the presence of lamalginite indicates that the Sangkarewang oil shale deposits were deposited in a fresh water to shallow marine environment.

Ilyas (2002) continued his work (2000) to develop a detailed exploration program in the Talawi area with drilling investigations. Seven holes were drilled to provide detailed stratigraphic correlation for the Sangkarewang oil shale deposit. Retort analysis from core samples indicates that the Sangkarewang oil shales yielded 35 to 50 litres of oil per tonne. Further investigations of oil yields, based on outcrop samples, are included elsewhere in this thesis.

52 CHAPTER 3

GEOLOGY OF THE TALAWI AREA

3.1. Introduction

This chapter describes more specifically the geological setting of the oil shale deposits in the Sangkarewang Formation within the Ombilin Basin. Observation has been carried out mainly in the western part of the basin and has indicated that oil shale deposits are widely distributed in the Talawi – Sawahlunto area. Hence, geological mapping and other studies of the oil shales for the thesis were concentrated in that area.

The main study area is located in the Talawi district, near Sawahlunto town, between 0o27’ and 0o45’ S and 100o30’ and 100o47’ E (Figure 3.1). The area has good road access since it is passed by the Trans Sumatra Highway. It can be reached easily from Padang (the capital city of West Sumatra province) by public transport, heading northeast with approximately 3 hours travel time.

Surface geological mapping has been carried out in the study area using a 1:50.000 scale topographic map as a basemap. Outcrops were observed both in the river beds and on road cuttings. Because the road cut outcrops have been subjected to intense weathering, observations were more focused on the rivers and streams in the study area.

The Talawi – Sawahlunto area is located in a valley surrounded by mountainous terrain. The vegetation in the valley is dominated by paddy rice, which provides the main Indonesian food supply. Most of the mountain ranges are covered by tropical rainforest. The southern part of study area belongs to the “Tambang Batubara Bukit Asam” (PTBA) coal concession, in which mining has been carried out since World War II.

53 100° E 101° E NORTH SUMATRA PROVINCE Rao

Pasarontang

Kamp Panti ar Rv. Kota Tengah

Air Bangis

M anat R LUBUK SIKAPING v. RIAU PROVINCE Malampah 0° 0° Sasak

PAYAKUMBUH BUKITTINGGI

LUBUK BASUNG

PADANG PANJANG BATUSANGKAR Buo

Ombi lin Rv. M S . in Rv g Talawi nto PARIAMAN L k Lu a a E k ra e k SAWAHLUNTO N T SIJUNJUNG Silungkang Tanjunggadang A W SOLOK Pulaupunjung A Sungaidareh IS PADANG 1° S 1° S T R Kotabaru A I T Terusan

PAINAN

Taratak

Balaisalasa

JAMBI PROVINCE

2° S 2° S Indrapura

Tapan

100° E 101° E

Figure 3.1 Location map of the study area

3.2. Lithologic Features

Field observation indicates that a number of different rock units are exposed in the study area. The basement rocks, which consist of Pre-Tertiary sediments and metasediments, occupy regions of high topography, particularly in the western part of the study area. Other Tertiary sedimentary rocks, as well as Quaternary deposits, are also exposed in the study area. In order to provide a reference framework, the stratigraphic nomenclature proposed by Koesoemadinata and Matasak (1981) is used as a basis for discussion in the present study. More complete descriptions of the rock units

54 are given below. A geological map of the area, prepared from field work carried out as part of the study, is provided as an enclosure (Appendix 1) accompanying this thesis.

3.2.1. Pre-Tertiary rocks The Pre-Tertiary rock units are mostly exposed in the southwest part of the study area. They are also exposed in the north (from Padang Ganting to Bukit Tungkar – see geological map in Appendix 1), as well as in the northeast. The Pre-Tertiary rock units are composed of metamorphic rocks as well as volcanic rocks. Since the present study was focused on the oil shale deposits in the Talawi area, geological mapping was more focused on the sedimentary rock units in the Talawi area and vicinity, rather than the basement materials.

According to Silitonga and Kastowo (1975), the Pre-Tertiary strata in the Talawi area consist of three rock units: the Permian Kuantan and Silungkang Formations, and the Triassic Tuhur Formation. The Kuantan Formation is divided into three members: the Lower Member, the Limestone Member and the Phyllite and Shale Member.

The Lower Member of the Kuantan Formation consists of quartzite and quartz sandstone with intercalations of phyllite, siliceous slate, shale, volcanic rock, chloritised tuff, conglomerate and chert. The Limestone Member consists of limestone, slate, phyllite, siliceous shale and quartzite. The Phyllite and Shale Member consists of shale and phyllite, with intercalations of quartzite, siltstone, chert and lava flows (Silitonga and Kastowo, 1975).

The Pre-Tertiary volcanic rocks are exposed in the northern part of the study area as granite (close to Padang Ganting, see geological map) and quartz porphyry (Bukit Tungkar). According to Silitonga and Kastowo (1975) the granite composition varies from leucogranite to quartz monzonite, whilst the quartz porphyry has phenocrysts of quartz and feldspar.

Two rock samples were taken from the Padang Ganting area (sample SR 43 – Figure 3.2) and the Ampang Nago River (SR 42 – Figure 3.3.). Thin sections were

55 prepared and analysed using optical microscopy techniques. Mineralogically, the rocks are composed mainly of K-feldspar, chlorite and sodium-rich plagioclase, which shows signs of early alteration. SR 42 has more biotite but less amphibole than SR 43. Both samples also have some opaque minerals, which may represent either iron oxide or iron sulphide. In general, the two samples have similar mineral contents and can be identified from thin section studies as granite.

pg Figure 3.2. Thin section of granite from Padang Ganting (SR-43) (Bt: Biotite, om: opaque mineral, pg: plagioclase)

Figure 3.3. Thin section of granite from Ampang Nago (SR-42)

The Permian Silungkang Formation is composed of limestone, which contains thin intercalations of shale, sandstone and tuff. In the study area the Silungkang Formation is exposed in a road cutting between Sawahlunto town and Muara Kelaban village (Figure 3.4).

56 Figure 3.4. The Permian Silungkang Formation near Muara Kelaban village

Silitonga and Kastowo (1975) have identified two members in the Triassic Tuhur Formation: the Slate and Shale Member, and the Limestone Member. The Slate and Shale Member of the Tuhur Formation is composed of slate, shale, marly shale intercalations of chert, radiolarite, black silicified shale and thin layers of metamorphosed greywacke. In the study area, this rock unit is exposed on the road between Muara Kelaban village and Sawahlunto town. The Limestone Member of the Tuhur Formation is composed of sandy limestone and conglomeratic limestone. This rock unit is also exposed in the southern part of the area near Sawahlunto town, as well as in the western part of study area close to Surauganting and Tanjung Bali villages (see geological map, Appendix 1).

3.2.2. Tertiary Sedimentary Rock Units

Four sedimentary rock units of Tertiary age are exposed in the study area. From oldest to youngest these are respectively the Brani, Sangkarewang, Sawahlunto and Ombilin Formations. Detailed descriptions of these units in the study area are given below.

57 3.2.2.1. Brani Formation

The Brani Formation is characterised by poorly bedded, poorly sorted to very poorly sorted breccias. The breccias contain blocks up to several metres in diameter, consisting of granite, quartzitic sandstone and limestone in a matrix of coarse to very coarse sandstone. Blocks of granite and quartz sandstone have angular form (Figure 3.5).

Two breccia samples were prepared as thin sections, one taken from the Malakutan River (SR-15) and another from near Tiga Tumpuk village (IR 5). The thin sections show that the breccias are composed of poorly sorted, mainly very angular detrital rock fragments (Figure 3.6). The breccias appear to have clastic textures with a grain supported fabric. Mineralogically they are composed mainly of quartz and carbonate (calcite), which are associated with feldspar (perthite and orthoclase) and opaque minerals (possibly iron oxide), as well as chlorite from plagioclase breakdown. Some plagioclase minerals are also partly replaced by calcite.

Figure 3.5. Breccia of the Brani Formation exposed in the area north of Sawahlunto town

58 Qz

Figure 3.6. Thin section of Brani breccia (Figure 3.5) showing quartz grains in carbonate matrix (Qz : quartz)

Although these rocks have clastic textures, the mineralogy and other features indicate a granitic derivation. The properties of the quartz, plagioclase and feldspar fragments show mainly a granitic origin. Unlike sedimentary quartz, which is characterized by rounded particles, both thin sections contain more angular, well- crystallized quartz, which resembles the characteristics of granitic quartz. The angular grains indicate high energy in transportation, which means that the sediment was transported only a short distance. From the thin section features the blocks have a very similar lithological composition to the surrounding matrix materials, which are calcareous and clay-rich sandstones.

According to Koesoemadinata and Matasak (1981), the Brani breccia has a typical purple brown colour. However, breccias in the present study area also show bluish, yellow and grey colours. De Smet (1991) assumed that the purple colour, which shows up as a network of cm-thick veins, in general indicate the former presence of rootlets. Field observation indicates that in the outcrop northeast of Talawi, along the road to Tiga Tumpuk (Appendix 1), the purple colour is lacking.

One interesting exposure was found in the Malakutan River (Figure 3.7). In this location the breccia is extremely poorly sorted. The rock is composed of some blocks of granite, quartz sandstone, and (Pre Tertiary?) limestone. The breccia is also very rich in reworked blocks and small fragments of the Sangkarewang shale. From the appearance of the folded shale, it appears that the shales have probably been reworked while they

59 were relatively soft. This exposure indicates that the Brani breccia overlies the Pre- Tertiary limestone as well as the Sangkarewang shale. This part of the Brani Formation is also interfingered with the Sangkarewang shale.

3.2.2.2. Sangkarewang Formation

The Sangkarewang Formation is distributed widely in the centre of the study area in a northwest – southeast direction. The distribution of the Sangkarewang Formation is bounded by Pre Tertiary rocks and younger sedimentary deposits, which belong to the Ombilin Formation. The distribution of the Sangkarewang Formation is also controlled by geological structures, which are very complex throughout the basin. According to Koning (1985), the formation extends underneath the larger part of the basin. Outcrops of the Sangkarewang Formation are well exposed in the Sangkarewang River, Malakutan River, Sipang River, Ampang Nago River and Sumpahan River as well as road cuts in Kolok, Bukitgadang and Tumpuk Tengah villages. The larger outcrops of the formation are restricted to the northwestern part of the basin.

Figure 3.7. Brani breccia with Sangkarewang shale fragment in Malakutan River

Generally the Sangkarewang Formation is characterised by laminated shales with a dark bluish grey to black colour. The weathering colour is yellowish brown (light

60 brown) and reddish brown (Figure 3.8). Locally the shales are calcareous. They fall apart easily along the laminae when dry and form thin, papery blades. The sediment is lacking bioturbation structures, but is often rich in plant remains, preserved on the bedding planes. Slump structures are rather characteristic. Intercalation of turbidite sandstone is common (Figure 3.9). The sandstone in the unit is characterised by a greenish grey colour and a light grey weathered colour, with fine – medium grains, good sorting, parallel bedding structures and plant remains.

Figure 3.8 Outcrop of the Sangkarewang shale in Sawahlunto area, close to the Sumpahan River

Figure 3.9. Turbidite sandstone intercalated with Sangkarewang shale in the Ampang Nago River

61 The intercalated turbidite beds contain features indicating a very high energy during deposition. The turbidite beds range up to 1 metre in thickness and locally have complete Bouma sets. The turbidites occur in units of several metres to tens of metres thickness without intercalation of shales, as in the Upper Sangkarewang in the Ampang Nago River. In between these units the turbidites alternate with the shales.

Initially the degree of exposure is poor, but higher up in the succession the outcrops are good. The percentage and thickness of turbidite sediment as well as the amount of slump phenomena increases while going upward in stratigraphy. The dip of the beds is more or less continuous to the southwest at an angle of up to 40o. The shales show dips up to vertical. To the north (Kolok – Tanjung Emas - see Appendix 1) the turbidites are lacking.

Calcareous clay can be found in the Sipang River and Sangkarewang River. Koesoemadinata and Matasak (1981) identified this rock as marl. In this study, however, the author prefers to name it as calcareous clay.

Outcrop on the road cut in Santur village (on the way to Kolok, close to Sangkarewang River) shows intercalated shales and sandstones, more sandy, coarse sand (gravel) to fine sand, fining upward. Outcrop features indicate an alluvial fan deposit. The presence of slump structures (which are dominant on the bottom of the outcrop) and thin sandstone layers indicates distal fan of alluvial fan deposit.

Outcrop features in Batang Ampang Nago show graded bedding and parallel bedding, as well as ripple marks on the shale surface. Graded bedding indicates turbidity current action at the time of deposition. This set of features indicates a turbidite facies, which was influenced by geological structures.

The Sangkarewang sandstone in Padang Ganting indicates a channel or river deposit. Outcrop features show massive coarse to fine grained sandstone. Several organized bedding structures are present, which have irregular convex bottom surfaces. According to De Smet (1991), the Sangkarewang Formation in the Selo River (NW Talawi) is very rich in turbidite beds (40% - 80%). The turbidites show

62 thicknesses up to 1 metre and locally have complete Bouma sets. The lithology features indicate characteristics of the distal part of a fan delta.

Field observation indicates that there are three types or three facies of the Sangkarewang oil shale, i.e. Type A, Type B, and Type C. Following are details of these three facies:

The Type A facies occurs in the lowest part of the Sangkarewang section and, consequently, is the oldest facies of the Sangkarewang. It is characterised by well- laminated, dark grey to grey, massive shales, intercalated with thin sandstone and claystone laminations. The laminae strike SE-NW and dip to the northeast (30o on average). This facies is mostly composed of laminated shales (up to 95%) with very thin laminated sandstone beds (less than 0.10 m – Figure 3.10). The shales are light brown to black, with very thin blades (papery structure). In some places the shale laminae are folded, and show slump structures. The sandstone layers are characterized by light grey colour, fine grains, ripple and parallel bedding, with carbonaceous fragments and occasional calcite veins. Thin coaly shale layers (approximately 0.20 m) also occur in the bottom part of this facies (sample SR 11). This facies can be traced in the southern part of the study area (Sawahlunto area), particularly in the Sumpahan River. For this reason, this facies is called the Sumpahan Facies.

The Type B or Santur Facies stratigraphically lies in the middle part of the Sangkarewang Formation. It is characterised by grey, well-laminated shales with carbonaceous fragments. Occasionally, breccia occurs and is associated with the shale laminae, for example in an exposure in the Malakutan River (Figure 3.8). Intercalated sandstones in this facies are thicker than in the Sumpahan facies (Type A). The strike of this rock unit is variable, E-W and NW-SE, with dip to the north (30o – 55o). The thickness of the oil shale deposit is also variable, ranging from 6m up to 26m. The Type B facies can be traced in the central part of the study area, near Santur and Kolok villages.

The Type C or Ampang Nago Facies is dominated by thick layers of sandstone. It characterised by thinly laminated shales, which are interlaminated with thick layers of

63 sandstone. The shale of this facies tends to be more fissile than other types. Turbidite beds are common in the sandstone. Individual turbidite beds can reach up to one metre in thickness. This facies, which is the youngest in the section, is distributed in the northern part of the study area, from Ampang Nago River to the Padang Ganting area.

Fold structure can be seen on the road to Padang Ganting. This folding was caused primarily by slumping (de Smet, 1991). The intercalated turbidite beds contain features indicating very high energy during deposition. The direction of the slumping was to the southwest.

3.2.2.3. Sawahlunto Formation

The Sawahlunto Formation is well exposed in the northeastern part of the study area. It is characterized by coal seams, which are being mined in this area.

According to Koesoemadinata and Matasak (1981) the Sawahlunto Formation is composed of a continental series of shales, micaceous siltstones and sandstones with interbedded coals.

The rock unit is characterised by multicoloured shales, siltstones and sandstones with intercalations of coal. The sandstones occur as channel fill and migrating point bar deposits. Very locally they are coarse to very coarse.

Multicoloured, clayey siltstones are also present with intercalations of yellow and brown quartz sandstone. The sandstones are well sorted, and coarse deposits are lacking. The siltstones are poorly cemented and non calcareous. Cross bedding in the sandstones is common.

The sequence includes channel-fill deposits consisting of fine-coarse poorly sorted cross-bedded sandstones which are brown in colour and locally contain pebbles. Well sorted to coarse and poorly sorted sandstones and even fine conglomerates are also present at the feet of mega cross beds and at the bottom of these channels

64 The Sawahlunto sediments are better rounded than those of the Brani Formation. The unit contains no fossils but is rich in pollen content (Koesoemadinata & Matasak, 1981).

3.2.2.4. Ombilin Formation

The Ombilin Formation is characterised by dark grey shales, which are often calcareous. Locally, they contain limestone lenses with coral debris, shell and plant remains in the centre of basin. The shales have intercalations of siltstones and glauconitic sandstones. This lithological unit is distributed with a north – south trend in the eastern part of the study area.

3.2.3. Quaternary Deposits

Some Quaternary deposits also exist in the central part of the study area (close to Kebon Tinggi village) as well as in the northern part of Tanjung Emas village. They are present as pumice in a glass shard matrix.

3.3. Stratigraphy

It is very obvious that the basement rock is the oldest rock unit in the study area. Based on radiometric dating Koning (1985) concluded that the basement rock is pre Tertiary in age. Tertiary sedimentation began with deposition of the Brani Formation during Eocene time. Subsequently, the Sangkarewang Formation was deposited. At some locations, the Malakutan River, for instance, the Brani breccia interfingers with the Sangkarewang shale. At other locations, however, the breccia occurs, as expected, above the Sangkarewang shale.

65 The Sawahlunto Formation overlies the Sangkarewang Formation. A very prominent contact between the Sangkarewang Formation and the Sawahlunto Formation can be observed in Sijantang Koto area.

The Brani Formation is the oldest of the four Tertiary rock units, and was deposited in the Early Oligocene. The Brani sequence is locally interfingered with, and therefore similar in age to the Sangkarewang rock unit. The Sawahlunto Formation overlies the Sangkarewang Formation conformably. This rock unit also lies underneath the Ombilin Formation.

3.4. Structural Geology

The Ombilin Basin has very complex structures as a result of tectonic movement in Sumatra. Anticlinal and synclinal structures are evidence of this tectonic movement, which was formed by the Plio-Pleistocene orogeny. One of these features can be observed in Talawi area as a syncline, which has 45o up to 60o dip on each flank. This fold formation was accompanied by faulting processes including strike-slip fault and thrust fault. One of the fault indications can be observed in a shale unit in the Sipang River.

66 CHAPTER 4

CHEMISTRY AND MINERALOGY OF THE SANGKAREWANG OIL SHALE DEPOSIT

Samples of the different lithologies in the Sangkarewang Formation of the Talawi area were subjected to analysis by a number of different techniques, to establish more fully the nature of the oil shale and associated strata. Among other factors, this was intended to evaluate the features that influence the yield of oil from different types of materials, and provide a framework for future economic assessments.

Knowledge of the inorganic components, as well as the organic constituents, is essential to many aspects of the geology of coal and oil shale (Ward, 1984, 1986; Diessel, 1992; Ward and Taylor, 1996; Taylor et al., 1998). Several methods can be used to determine the inorganic and organic constituents of oil shale, and these are briefly discussed in other chapters. A total of 23 samples were analysed, using the methods summarized in Table 4.1. The location, stratigraphy and lithology of the samples studied are also noted in Table 4.1, and are discussed more fully in the previous chapter; the locations are also shown on the geological map in Appendix 1.

Detailed explanations of the procedures used for each analysis are given in the following sections.

4.1. Chemical analysis

Because their fine grain size limits the use of microscope techniques, chemical analysis is one of the main sources of data about the composition of shales. According to Pettijohn (1975), silica is the dominant constituent of clays and shales. Alumina is an essential constituent of the clay minerals, as well as a component of unweathered detrital alumino-silicates – primarily feldspars. Iron in shales is present as an oxide

67 pigment, as part of the chlorite and other clays, and exceptionally as pyrite, marcasite, siderite, or authigenic iron silicate (chamosite).

Table 4.1. List of samples analysed

Sample Location Lithology Facies XRD XRF C&S TS PS Fischer SR 28 Sawahlunto Coal Sawahlunto Fm X SR 11 Sumpahan River Coaly shale Ampang Nago X X X X X SR 23 Shale Ampang Nago X X X X SR 34 Shale Ampang Nago X X X X SR 24 Shale Ampang Nago X X X X SR 44 Shale Ampang Nago X X X SR 3 Sumpahan River Shale Ampang Nago X X X SR 35 Sumpahan River Shale Ampang Nago X X X X X SR 32 Sumpahan Rive Shale Ampang Nago X X X X SR 30 Shale Santur X X SR 15 Malakutan River Shale Santur X X X X X SR 17 Malakutan River Shale in breccia Santur X X X X X SR 21 Kolok Sandstone Santur X X X SR 25 Kolok Sandstone Santur X X SR 5 Talawi Shale Sumpahan X X X SR 8 Talawi Sandstone Sumpahan X X X SR 14 Sipang River Shale Sumpahan X X X X X SR 7 Sipang River Shale Sumpahan X X X X SR 19 Sipang River Shale Sumpahan X X X X X SR 6 Sipang River Shale Sumpahan X X X X SR 26 Sipang River Sandstone Sumpahan X X X X SR 42 Ampang Nago Sandstone Sumpahan X X X X X SR 37 Ampang Nago Shale Sumpahan X X X X X SR 43 Padang Ganting Sandstone Sumpahan X X X XRD X-ray diffraction analysis XRF X-ray fluorescence analysis (major and minor elements) C & S Carbon and Sulphur determination TS Thin section petrology PS Polished section petrology Fischer Fischer assay

There are some relations between chemical composition of shales and the environment of deposition. Millot (1949) contended that shales of freshwater, brackish and marine origin differed in their bulk chemical composition. Freshwater shales, for instance, were lower in both K2O and MgO than either marine or lagoonal shales.

The chemical composition of oil shale may vary depending on the type of oil shale represented. As an example, Table 4.2 describes a comparison of the chemical composition of some siliclastic and carbonate-rich oil shales.

The chemical composition of the organic matter in oil shale may also vary to a large extent. According to Cane (1976), the elemental composition always shows a high hydrogen content. The atomic H/C ratio for the organic matter in oil shale ranges from 1.25 to 1.75. The oxygen content is rather variable, and as a result the atomic O/C ratio ranges from 0.02 to 0.20. Nitrogen is much less abundant, and also varies a great deal. The atomic N/C ratio ranges from 0.5 x 10 -2 to 5.8 x 10-2.

Table 4.2. Chemical composition of oil shales (Greensmith, 1978)

Scottish shale Green River shale, Colorado (siliciclastic) (carbonate-rich) Ash (%) 78 65 SiO2 56.7 42.4 Al2O3 25.0 10.5 Chemical Fe2O3 9.9 4.7 composition CaO 2.7 23.5 of ash(%) MgO 3.1 9.3 Na2O + K2O 2.0 7.6 SO3 0.9 2.0

Chemical analyses have been done for the present study in order to obtain a better understanding of the chemical properties of the Sangkarewang oil shale deposit. The laboratory program included major element analysis using X-ray fluorescence methods and carbon and sulphur determinations using a LECO CNS-2000 elemental analyser.

4.1.1. X-Ray Fluorescence Analysis

4.1.1.1. Background

X-ray fluorescence spectrometry is a standard technique used for the chemical analysis of mudrocks, less often for sandstones and rarely for carbonates and evaporites (Fairchild et al., 1988). In particular, X-ray fluorescence spectrometry gives quantitative data on a range of inorganic components. X-ray fluorescence is ideal for the determination of major and minor elements such as Si, Al, Mg, Ca, Fe, K, Na, Ti, S and P in siliclastic rocks (Fairchild et al., 1988). For organic-rich rocks such as oil shale, the analysis provides a meticulous quantitative estimate of the proportion of the different

69 elements present in the ash remaining after high temperature combustion. The proportions of these elements as determined in the present study, including the loss of mass associated with the ashing (loss on ignition), were expressed as percentages of the original oil shale in oxide form.

Several authors have discussed the principle of X-ray fluorescence analysis, including Jenkins and de Vries (1970), Bertin (1975), Johnson and Maxwell (1981), and Tertian and Claisse (1982). Basically, the impact of high energy X-rays on a rock sample produces a spectrum of secondary radiation with particular wavelengths and intensities. The intensity of characteristic radiation at particular wavelengths represents the elements present and their concentration in the analysed sample.

4.1.1.2. Analytical Method

X-ray fluorescence analysis for major element determination in the present study required the sample to be incorporated as a solid solution in the form of a glass disc. The rock samples were powdered in a ring-grinder mill, and then oven dried at 80oC. The dried powders were calcined at 1050oC, and the loss-on-ignition determined. This process was equivalent to preparing a high-temperature ash in the case of oil shales. The calcined shale was then fused with lithium tetraborate and cast into a mould.

Sample preparation followed the procedure of Norrish and Hutton (1969). Glass sample buttons were prepared using a mixture of flux and sample in the approximate ratio 5.43:1. The flux used to fuse the rock samples was composed of borate glass and ammonium nitrate in the exact ratio 75:1. The borate glass flux was prepared from lithium tetraborate (Li2O.2B2O3) 47% wt, lithium carbonate (Li2CO3) 36.6% wt and lanthanum oxide (La2O3) 16.4% wt.

To prepare each 40 mm disc, the amounts of flux and sample were weighed as follows: Flux = 4.50 g Powdered sample = 0.84 g Ammonium nitrate = 0.06 g (approximately)

The mixture was heated in a platinum-gold crucible for 15 minutes at 1050oC until the specimen had dissolved and effervescence had ceased. The melt was poured into a graphite disc which was held on a hot plate at about 220oC. An aluminium plunger was then brought down gently to mould and quench the melt. The major and minor elements were analysed by X-ray fluorescence spectrometry of each disc, using a Philips PW 2400 spectrometer system.

The Philips PW 2400 spectrometer system used SuperQ/Quantitative software for major element determination. Prior to analysis, the Philips PW 2400 spectrometer system was set up using Certified Reference Materials. Key parameters were calibrated in this process including intensity, wavelength and matrix components. The calibration process resulted in a calibrated graph for each element. As an example, Figure 4.1 shows a calibrated graph for K2O from the Philips PW 2400 calibration. A straight line represents a perfect calibration obtained from a given element. The analysis result from an unknown sample, for example a sample tested in the present study, will fall as a point somewhere on the graph. This point is then projected to the calibrated straight line to find the K2O percentage of the given sample. Other major element determinations were also performed using the same procedure.

4.1.1.3. Results

Twenty-three samples were subjected to this type of analysis, with the results given in Tables 4.3 and 4.4. Of all major oxides, SiO2 is the dominant component present in the rock samples. Al2O3 is the second most dominant oxide, although some samples have CaO as their second major component (e.g. SR 25 and SR 17). Traces of

V2O5, Cr2O3, NiO, CuO, ZnO, As2O3, Rb2O, SrO, Y2O3, ZrO2, BaO, CeO2, PbO, ThO2 and U3O8 were also identified (less than 0.01%) in conjunction with the major element (oxide) determinations.

71 Figure 4.1. A calibrated graph for K2O from the Philips PW 2400 calibration process

72 Table 4.3. Major element oxides from X-ray fluorescence analysis

Sample Major Elements (%) LoI Total Number Na2O MgO Al2O3 SiO2 P2O5 SO3 K2O CaO TiO2 MnO Fe2O3 (%) (%) SR 11 0.25 2.49 0.43 1.83 0.045 1.262 0.266 20.41 0.049 0.074 3.23 71.50 100.94 SR 32 0.31 1.48 17.79 43.81 0.184 2.134 1.821 7.11 0.590 0.274 7.28 17.88 98.75 SR 23 0.44 1.35 14.76 40.09 0.161 2.395 1.572 12.70 0.524 0.124 6.18 20.53 98.63 SR 34 0.45 1.51 17.70 42.23 0.188 2.841 1.855 8.95 0.541 0.094 6.11 19.38 99.14 SR 24 0.32 1.39 17.72 43.60 0.175 2.172 1.793 8.06 0.598 0.186 7.08 18.29 99.42 SR 44 0.20 0.71 21.41 48.92 0.619 3.298 2.170 0.11 0.627 0.010 4.65 19.64 99.44 SR 35 0.21 1.02 11.62 26.13 0.115 3.432 0.861 22.83 0.337 0.055 4.72 31.69 99.86 SR 3 0.38 0.92 8.78 23.54 0.262 2.647 0.980 26.16 0.239 0.093 5.09 33.24 99.87 SR 30 3.31 0.34 18.87 61.24 0.099 0.171 2.968 2.16 0.719 0.125 5.25 6.35 101.58 SR 21 0.84 1.22 11.84 64.35 0.086 1.403 1.212 6.67 0.561 0.635 2.59 9.11 99.31 SR 25 1.13 1.20 7.32 32.68 0.082 0.757 1.029 28.47 0.300 0.290 2.96 24.5 100.14 SR 15 1.34 1.71 14.91 46.92 0.157 1.365 1.365 9.27 0.507 0.132 7.41 18.56 102.4 SR 17 0.83 0.76 3.60 43.74 0.246 0.521 0.700 25.54 0.215 0.291 1.94 21.2 99.28 SR 43 2.85 2.09 15.27 63.19 0.122 0.044 1.916 1.73 0.688 0.094 6.74 4.56 99.42 SR 42 2.40 1.82 14.14 60.51 0.124 0.116 2.643 4.10 0.441 0.089 6.41 6.23 99.01 SR 37 1.07 1.93 16.48 40.84 0.155 0.253 2.124 8.50 0.698 0.087 5.64 23.17 100.92 SR 5 1.69 2.00 15.30 51.19 0.186 0.523 2.294 7.34 0.608 0.086 6.35 13.17 100.45 SR 8 2.55 2.06 15.21 59.85 0.134 0.150 2.477 3.29 0.549 0.063 7.09 6.07 99.52 SR 26 2.47 1.18 14.41 63.52 0.156 0.808 2.094 4.32 0.490 0.058 3.37 7.11 99.3 SR 19 0.93 1.33 15.22 46.16 0.112 0.579 1.772 9.93 0.585 0.067 5.05 18.09 99.41 SR 14 1.33 1.66 18.07 49.69 0.176 0.643 2.189 5.45 0.714 0.037 4.32 16.03 99.88 SR 7 0.84 1.81 22.39 49.80 0.129 0.199 2.274 0.96 1.008 0.048 6.18 13.9 99.5 SR 6 0.95 1.24 19.41 52.67 0.081 0.279 1.946 4.80 0.745 0.030 3.66 13.98 99.7 Max 3.31 2.49 22.39 64.35 0.62 3.43 2.97 28.47 1.01 0.64 7.41 71.50 102.40 Min 0.20 0.34 0.43 1.83 0.05 0.04 0.27 0.11 0.05 0.01 1.94 4.56 98.63 Mean 1.18 1.44 14.46 45.93 0.16 1.22 1.75 9.95 0.54 0.13 5.19 18.88 99.82 Std Dev 0.93 0.51 5.31 14.77 0.11 1.11 0.67 8.60 0.21 0.14 1.62 13.83 0.91

73 Table 4.4. Minor elements from X-ray fluorescence analysis, expressed as oxides

Sample Minor Elements (ppm) Number V2O5 Cr2O3 NiO CuO ZnO As2O3 Rb2O SrO Y2O3 ZrO2 BaO CeO2 PbO ThO2 U3O8 SR 11 1100 330 50 50 10 140 60 310 bld 10 570 1500 400 1240 270 SR 32 2400 bld bld 60 100 20 10 150 70 120 120 450 110 250 70 SR 23 2200 bld 20 60 100 20 30 190 60 130 60 430 110 380 90 SR 34 2700 40 bld 70 80 20 10 170 70 110 160 370 100 310 80 SR 24 2300 30 bld 70 90 30 10 150 60 130 160 370 100 260 70 SR 44 300 100 40 150 40 40 40 220 150 150 910 740 160 240 70 SR 35 2500 110 40 70 170 Bld 40 330 40 70 150 650 190 670 140 SR 3 2300 50 50 50 50 10 60 340 50 90 130 640 170 740 150 SR 30 60 90 30 20 70 30 10 290 90 380 670 90 30 80 10 SR 21 1600 200 90 60 90 70 30 80 70 310 170 260 80 240 50 SR 25 1500 50 60 70 40 10 70 380 50 100 150 460 140 710 130 SR 15 2400 bld bld 60 90 60 60 200 70 120 bld 350 110 240 60 SR 17 1100 60 50 40 20 Bld 70 420 60 160 120 460 120 650 130 SR 43 2500 70 bld 70 70 30 40 230 70 440 230 150 20 40 20 SR 42 1200 10 30 20 40 20 10 250 60 230 270 160 40 100 40 SR 37 2300 60 bld 40 70 10 bld 210 60 150 270 490 160 360 80 SR 5 1800 bld 20 40 70 10 10 230 70 290 400 310 100 220 50 SR 8 1400 100 bld 50 50 30 30 220 70 310 250 170 bld 70 30 SR 26 1200 100 20 20 80 40 30 240 70 520 280 180 50 190 40 SR 19 2600 bld 20 30 80 10 20 170 70 160 160 430 140 340 80 SR 14 2500 bld bld 50 120 10 bld 140 80 230 190 400 90 270 70 SR 7 2800 bld bld 120 150 50 bld 90 60 220 190 380 90 140 40 SR 6 3300 30 bld 170 90 30 10 120 60 170 160 340 80 240 50 Max 3300 330 90 170 170 140 70 420 150 520 910 1500 400 1240 270 Min 60 10 20 20 10 10 10 80 40 10 60 90 20 40 10 Mean 1916 89 40 63 77 33 33 223 69 200 262 425 118 347 79 Std Dev 819 78 20 38 38 30 22 89 21 125 205 286 77 281 56

74 4.1.2. Carbon and Sulphur Determination

4.1.2.1. Background

Generally, the organic carbon content of oil shales is more than 2.3-5% (Tissot and Welte, 1978) and rarely exceeds 40%. The amount of organic carbon in a rock depends on the conditions of the sedimentary environment in which it accumulated. According to Taylor et al (1998), an extremely high organic carbon content occurs in lake sediments formed within mires, for example those in which mineral-poor torbanites or sapropelic coals were deposited; although richer than those of the present study, such materials may be considered as oil shales. High proportions of organic carbon may also be found in other lacustrine oil shales. By contrast, marine oil shales usually contain less than 15% organic carbon and deep-water oceanic sediments are characterized by less than 10% organic carbon content (Taylor et al, 1998).

The organic carbon contents, as well as the total carbon and sulphur contents of the rock samples, were determined for the present study using a LECO CNS-2000 elemental analyser. This is a non-dispersive, infrared, microcomputer based instrument, designed to measure the carbon, nitrogen and sulphur content in a wide variety of materials (LECO manual).

4.1.2.2. Analytical Method

The rock samples were crushed to powder size, and dried in an oven at 80oC for about 1 hour to remove moisture from the samples. Approximately 0.5 grams of each dried sample was placed in a sample holder, referred to as a boat (Figure 4.2). Each sample was then put into the small opening on the LECO CNS-2000 unit (Figure 4.3). The “Analyze” menu was selected on the screen and the boat was automatically pushed into the combustion chamber, allowing the machine to burn the sample. The combustion process transformed any elemental carbon and sulphur into CO2 and SO2, which were then determined by infra-red spectrometry. The analysis process ended with the display of the carbon and sulphur contents on the screen, and an associated hard-copy print-out.

Figure 4.2. Sample holder (“boat”) to be analysed by LECO CNS-2000

Figure 4.3. Sample on boat being inserted into LECO CNS-2000

The carbon content determined by the LECO CNS-2000 represents the total carbon content of the sample analysed. For a raw oil shale, this includes both the organic carbon and the inorganic (carbonate) carbon contents. Special treatment was therefore carried out in order to determine the organic carbon content of the rock sample by a separate analysis process.

Samples for organic carbon determination were treated with hydrochloric acid prior to analysis. Approximately 0.5 grams of powdered sample was placed into a boat and mixed with 3 ml of 50% hydrochloric acid for about 1 hour. This was intended to dissolve any carbonate carbon in the rock sample, converting it to CO2 before introduction to the analysis process but leaving the organic carbon unaffected. Hydrochloric acid dissolves the main carbonate minerals, and is also generally used for the decomposition of carbonate rocks and the separation of any acid-insoluble silicate or

76 oxide minerals. Each sample was then washed by running warm water into the boat for about 10 to 20 times or until the effervescence had ceased. The boat was made from a porous material thus the water ‘escaped’ from the boat after the rock sample had been washed to remove the surplus acid. Each sample was dried in an oven to remove any remaining water in the sample. After this acid treatment, the dried boat with the sample was inserted into the LECO CNS-2000, using a similar procedure to that previously described. In this case the carbon content indicated by the analysis was the organic carbon content of the rock sample.

4.1.2.3. Results The sulphur, total carbon and organic carbon contents of each rock sample are presented in Table 4.5. Most of the rock samples from the Sangkarewang sequence have a very low percentage of sulphur (less than 1%). The highest sulphur content is only 2.05% (SR 44).

Table 4.5. Results of sulphur and carbon analysis

Sample Sulphur Total Organic Carbonate Lithology No. (%) Carbon (%) Carbon (%) Carbon (%) SR 11 Coaly shale 0.24 43.92 40.94 2.98 SR 32 Shale 0.43 5.49 3.8 1.69 SR 23 Shale 0.24 6.71 3.87 2.85 SR 34 Shale 0.36 6.50 4.82 1.69 SR 24 Shale 0.02 5.76 4.10 1.66 SR 44 Shale 2.05 8.61 8.58 0.03 SR 35 Shale 0.60 12.81 9.36 3.45 SR 3 Shale 0.22 11.98 6.75 5.24 SR 15 Shale 0.12 5.21 3.4 1.81 SR 17 Shale 0.01 8.54 1.17 7.37 SR 42 Sandstone 0.01 9.07 6.86 2.22 SR 37 Shale 0.00 9.4 7.05 2.35 SR 5 Shale 0.03 3.86 2.43 1.43 SR 26 Sandstone 0.10 1.58 0.66 0.92 SR 19 Shale 0.02 6.01 4.03 1.98 SR 8 Sandstone 0.02 6.08 4.21 1.87 SR 14 Shale 0.03 5.70 4.70 1.00 SR 6 Shale 0.08 3.13 2.41 0.73 Mean 0.25 8.91 6.62 2.29 Min 0.00 1.58 0.66 0.03 Max 2.05 43.92 40.94 7.37 Std Dev 0.48 9.19 8.88 1.72

77 It can be seen from Table 4.5 that in many cases only relatively minor differences exist between the percentages of total carbon and organic carbon for each rock sample. This suggests that the organic carbon content of the rock samples, with some exceptions (e.g. SR 17), is often much more abundant than the inorganic carbon content. There is also a relatively limited range of total carbon contents for almost the entire suite of rock samples. The exception is sample SR 11, which has the highest proportion of organic carbon (40.94 %), and, for reasons discussed elsewhere in this thesis, is in reality a coal sample. Overall, the total carbon content of the rock samples studied tends to decrease from the lower to the upper part of the Sangkarewang Formation. Variation in lithology (shale and sandstone) is not significantly associated with variation in the carbon content.

Generally, the sulphur contents of the Sangkarewang samples as determined by the LECO are mainly quite low (except for sample SR 44). The results are different from the sulphur obtained (as SO3) by XRF analysis as shown in Table 4.6, mainly because a catalyst to release S from sulphates was not used in the LECO analyses.

Table 4.6. Sulphur obtained by calculation

Sample Lithology SO3 (%) Sulphur (%) No. from XRF derived from SO3 LECO SR 11 Coaly shale 1.26 0.5 0.24 SR 32 Shale 2.13 0.85 0.43 SR 23 Shale 2.40 0.96 0.24 SR 34 Shale 2.84 1.14 0.36 SR 24 Shale 2.17 0.87 0.02 SR 44 Shale 3.30 1.32 2.05 SR 35 Shale 3.43 1.37 0.60 SR 3 Shale 2.65 1.06 0.22 SR 15 Shale 1.37 0.55 0.12 SR 17 Shale 0.52 0.21 0.01 SR 42 Sandstone 0.12 0.05 0.01 SR 37 Shale 0.25 0.10 0.00 SR 5 Shale 0.52 0.21 0.03 SR 26 Sandstone 0.81 0.32 0.10 SR 8 Sandstone 0.15 0.06 0.02 SR 19 Shale 0.58 0.23 0.02 SR 14 Shale 0.64 0.26 0.03 SR 6 Shale 0.28 0.11 0.08

78 4.2. Mineralogy

4.2.1. Background

Oil shale is composed of mineral matter and organic matter. In particular, 25% of the total rock volume in a typical shale is composed of clay minerals (Picard, 1953). Consequently, knowledge of clay mineralogy is needed in order to understand fully the properties of shale, including oil shale. Moreover, knowledge of the clay minerals can provide a good contribution to provenance studies, as well as an understanding of burial history (Hardy and Tucker, 1988).

Clay minerals are small particles of hydrous silicates with an effective diameter of less than 2m (Grim, 1953; Weaver, 1989; Velde, 1992; Moore and Reynolds, 1997). Classifications of clay minerals have been proposed by some authors (e.g. Grim, 1953; Moore and Reynolds, 1997). These classifications are mainly based on the crystal structure of the minerals (e.g. layer type, layer charge, type of interlayer material and type of octahedral sheet). Some of these classifications also include non-clay minerals such as the micas, which are often associated with clay minerals. Tables 4.7, 4.8 and 4.9, provide classifications given by several different authors.

Weaver’s (1989) classification is very similar to that of Moore and Reynolds (1997), and both classifications are based on the same source (Bailey, 1980b). Moore and Reynolds (1997), however, also refer in their classification to other works (Bailey, 1980a,b; Brindley, 1981; Hower and Mowatt, 1966 and Šrodoñ, 1984). The classification of Moore and Reynolds (1997) includes illite as a separate group, whereas Weaver (1989) did not include illite in his classification. Another difference is in the layer type for chlorite.

Table 4.7. Classification of the clay minerals (Grim, 1953)

I. Amourphous Allophane group II. Crystalline A. Two-layer type (sheet structures composed of units of one layer of silica tetrahedrons and one layer of alumina octahedrons) 1. Equidimensional Kaolinite group: Kaolinite, necrite, etc. 2. Elongate Halloysite group B. Three-layer types (sheet structures composed of two layers of silica tetrahedrous and one central dioctahedral or trioctahedral layer 1. Expanding lattice a. Equidimensional Montmorillonite group: Montmorillonite, sauconite, etc. Vermiculite b. Elongate Montmorillonite group: Nontronite, saponite, hectorite 2. Nonexpanding lattice Illite group C. Regular mixed-layer types (ordered stacking of alternate layers of different types) Chlorite group D. Chain-structure types (hornblende-like chains of silica tetrahedrons linked together by octahedral groups of oxygens and hydroxyls containing Al and Mg atoms) Attapulgite Sepiolite Palygorskite

80 Table 4.8. Classification of phyllosilicates related to clay minerals (Weaver, 1989, modified from Bailey, 1980b)

Layer Group (x = Sub-group Species** type charge per unit)* 1:1 Serpentine-kaolin Serpentines Chrysolite, antigorite, lizardite, amesite, (x~0) Kaolins berthierine Kaolinite, dickite, nacrite 2:1 Talc-pyrophyllite Talcs Talc, willemseite (x~0) Pyrophyllites Pyrophyllite Smectite Saponites Saponite, hectorite, stevensite (x~0.2-0.6) Montmorillonites Montmorillonite, beidellite, nontronite Vermiculite Trioctahedral vermiculites Trioctahedral vermiculites (x~0.6-0.9) Dioctahedral vermiculites Dioctahedral vermiculite Mica Trioctahedral micas (x~1.0) Dioctahedral micas Muscovite, paragonite, illite, phengite, celadonite, glauconite Brittle Mica Trioctahedral brittle micas Clintonite, anandite (x~2.0) Dioctahedral brittle micas Margarite 2:1:1 Chlorite Trioctahedral chlorite Clinochlore, chamosite, nimite (x~variable) Dioctahedral chlorite Donbassite Di,trioctahedral chlorite Cookeite, sudoite 2:1 Sepiolite- Sepiolites Sepiolite, loughlinite inverted palygorskite Palygorskites Palygorskite (attapulgite) ribbon (x~variable) * x refers to the charge on an O10(OH)2 formula unit for smectite, vermiculite, mica and brittle mica. ** Only a few examples are given

Table 4.9. Classification of phyllosilicates with emphasis on clay minerals (Moore and Reynolds, 1997)

Layer type Group Subgroup Species 1:1 Serpentine-kaolin Serpentines (Tr) Chrysotile, antigorite, lizardite, berthierine (x~0) Kaolins (Di) Kaolinite, dickite, nacrite, halloysite 2:1 Talc-pyrophyllite Talc (Tr) (x~0) Pyrophyllite (Di) Smectite Tr smectites Saponite, hectorite (x~0.2-0.6) Di smectites Montmorillonite, beidellite, nontronite Vermiculite Tr vermiculites (x~0.6-0.9) Di vermiculites Illite Tr illite? (x<0.9>0.6) Di illite Mica Tr micas Biotite, phlogopite, lepidolite (x~1.0) Di micas Muscovite, paragonite Brittle mica Di brittle micas Margarite (x~2.0) Chlorite Tr,Tr chlorites Common, name based on Fe2+, Mg2+, Mn2+, Ni2+ (x variable) Di,Di chlorites Donbassite Di,Tr chlorites Sudoite, cookeite (Li) Tr,Di chlorites …………………………………………………………………………………………… 2:1 Sepiolite-palygorskite Inverted ribbons (with x variable) Tr = trioctahedral and Di = dioctahedral; x = charge per formula unit. Based on Bailey (1980a,b), Brindley (1981), Hower and Mowatt (1966) and Šrodoñ (1984).

81 Based on their swelling properties, Velde (1992) divided the clay minerals into swelling and non-swelling types. Table 4.10 illustrates the detailed clay division of Velde (1992).

Table 4.10. Clay classification of Velde (1992)

Dominant elements Basal spacing (Å) Glycol Dry SWELLING TYPES Smectites Beidellite Al 17 10 Montmorillonite Al (Mg, Fe2+ minor) 17 10 Nontronite Fe3+ 17 10 Saponite Mg, Al 17 10 Vermiculite Mg, Fe2+, Al (Fe3+ minor 15.5 10-12 Mixed layer minerals* 10-17 < 10

NON SWELLING TYPES Illite K, Al (Fe, Mg minor) 10 Glauconite K, Fe2+, Fe3+ 10 Celadonite K, Fe2+, Mg, Fe3+, Al3+ 10 Chlorite Mg, Fe, Al 14 Berthiérine Fe2+, Al3+ (minor Mg) 7 Kaolinite Al 7 Halloysite Al 10.2 Sepiolite Mg, Al 12.4 Palygorskite Mg, Al 10.5 Talc Mg, Fe2+ 9.6 * Two or more types of basic layer interstratified in the same crystal

One of the main methods for identifying and analysing mineral matter in rocks and sediments, including oil shales, is X-ray diffraction. This method has been considered as an appropriate way to identify mineral matter in fine-grained rocks, particularly for clay-bearing rock samples. The principles of X-ray diffraction have been discussed by several authors, such as Grim (1953), Klug and Alexander (1974), Hardy and Tucker (1988), and Moore and Reynolds (1997).

Clay minerals can be identified by their dominant chemical elements, and especially by the distance between the (001) layers in their crystal structure or their basal d spacing (Velde, 1992). Clay minerals have characteristic basal (001) d spacings when subjected to X-ray diffraction under different conditions (Table 4.10).

X-ray diffraction has been used for many years as a definitive basis for mineral identification. In this regard it is especially useful for study of fine-grained rocks, such

82 as shales, in which the minerals cannot be identified adequately by optical methods. It is particularly well suited to identification of clay minerals, which typically cannot be reliably identified by other techniques.

4.2.2. XRD Analysis Techniques

A number of different methods have been used for X-ray diffraction analysis of clay-bearing mixtures (Gibbs, 1971; Hardy and Tucker, 1988; Velde, 1992; and Moore and Reynolds, 1997). These usually include separate diffractometry studies of the clay fraction, prepared as an orientated aggregate after concentration by settling.

Sample preparation techniques for X-ray diffraction analysis may vary, depending on the availability of samples and equipment, the analysis purpose, and the type of sample, as well as comprehension of X-ray diffraction principles (Moore and Reynolds, 1997). The sample preparation technique for the present study used a combination of powder analysis (cavity mount) and slide analysis (orientated aggregate) techniques.

Powder Diffractometry

To begin with, the whole-rock samples were ground to less than about 200 mesh (<63m) prior to analysis. Each powdered sample was placed in an aluminium cavity holder as randomly oriented particles (Figure 4.19). The powders were than subjected to X-ray diffractometry using a Philips X’pert integrated diffractometer system (Figure 4.20), with Bragg-Brentano goniometer configuration and Philips APD control and display software.

X-ray diffraction patterns were collected for each of the 21 samples from the digital-recording diffractometer using Cu-K radiation ( = 1.5418Å) from 2° to 60° 2, with 0.04° step and two second step count. Each scan was stored as a computer file (Philips .RD format), and used to produce a diffractogram representing the response of

83 the mineral mixture to the diffraction process. These diffractograms were displayed using both Philips APD and CSIRO X-Plot software. The d spacing of the minerals present allowed them to be identified by reference to the ICDD powder diffraction file using the search-match routine in the X-Plot display software system.

Figure 4.4. A powdered sample on an aluminium cavity sample holder in the centre of XRD goniometer chamber

Figure 4.5. Philips goniometer with the sample chamber on the centre

Oriented-aggregate X-ray Diffractometry

Oriented aggregates of the clay (<2m) fraction for each sample were prepared to study the clay minerals more closely, especially the expandable-lattice clay minerals. Initially, 3-5 grams of each sample was dispersed in water to concentrate its clay fraction by settling out of the coarser components. Care was taken to avoid flocculation, which would cause the fine particles to settle too quickly, and would produce a random orientation diffraction pattern at the completion of the preparation process. A small amount of sodium hexametaphosphate (Calgon) was added into the mixture as a

84 deflocculant, to prevent flocculation and ensure dispersion of the clay minerals in the suspension.

The material remaining in suspension at a certain depth, after settling for a period of time determined by Stokes Law (Hardy and Tucker, 1988), was recovered by pipette as the fraction with an effective diameter of less than 2m. In order to obtain further concentration of this fraction, the recovered less than 2m fraction was then centrifuged, and the supernatant water decanted to concentrate the solid particles. The concentrated clay fraction was then dropped on to a small glass slide (Figure 4.6), using the pipette-on-glass-slide technique of Gibbs (1965). This was intended to produce an orientation of the platy clay minerals parallel to the surface of the glass substrate, allowing presentation of the basal (001) planes of the clay minerals to the X-ray beam for more detailed study.

Figure 4.6. Preparation of oriented aggregates of clay fractions, showing beakers for settling in the background and glass slides with clay concentrates in the foreground

The orientated aggregate slide was then placed, for minimum of 16 hours or overnight, in a desiccator partly filled with ethylene glycol. Each slide was subjected to X-ray diffraction after this ethylene glycol treatment. Ethylene glycol vapour systematically intercalates itself into the interlayer areas of any expandable clay minerals. As a result, the diffractogram obtained from an oriented aggregate after glycol

85 treatment will produce a basal d spacing for smectite which stabilises at 17Å (Hardy and Tucker, 1988; Moore and Reynolds, 1997). This glycol treatment is very useful in identifying the various clay minerals (see Table 4.10), including the mixed-layer clay materials.

Another treatment, used after glycol saturation, was to heat the oriented aggregate in a furnace at 400oC for approximately 1 hour. This was intended to remove any interlayer water from the clay minerals, or the interlayered organics from glycolated samples. Considered together with the results from the glycol treatment, XRD of the heated samples allowed more precise identification of the individual clay minerals present. Smectite, for instance, collapses to 10Å after this heat treatment (Deer et al, 1992; Moore and Reynolds, 1997).

The minerals represented in both the randomly-oriented and oriented-aggregate diffractograms were identified using the search-match routine in the X-Plot software system (Raven, 1996). This software allows identification of each mineral from its pattern of d spacings by reference to the ICDD powder diffraction file. Figure 4.7 illustrates the XRD patterns from SR 37 powdered, glycolated and heated 400oC, as displayed by X-Plot software.

Quantitative XRD Analysis

Quantitative analysis of the mineral proportions in each powdered rock sample was carried out using the Siroquant1 XRD processing system (Taylor, 1991). Siroquant provides quantitative analysis of X-ray diffractometry data using a Rietveld-based computational method (Rietveld, 1969), combined with corrections for absorption contrast (Brindley, 1981) and preferred orientation effects, to provide data on the percentages of individual crystalline materials (minerals) without the necessity for addition of a mineral spike as required by more traditional procedures (Ward and Taylor, 1996). Siroquant can also be used to indicate the proportion of any non- crystalline or amorphous material present in the sample, with the addition of a weighed- in spike component (Ward et al, 1999).

Figure 4.7. XRD pattern from SR 37 (powdered, glycolated and heated up to 400oC)

87 In order to quantitatively analyse each mineral present in the samples, Rietveld- format XRD data (.hkl) files were created by Siroquant for each mineral likely to be present, drawing on a comprehensive collection of crystal-structure information in the Siroquant database. These were produced by Siroquant as ASCII files listing (hkl) and F(hkl) values. They also incorporated information on the plane nominated within each mineral to control preferred-orientation effects, and data to allow for anomalous dispersion of the XRD beam by iron and related constituents.

For each individual analysis, a task (.tsk) file was set up with a listing of the minerals expected to be present (i.e., the .hkl files to be used in the analysis) and the relevant sample XRD pattern. Corrections were made to remove the background from the sample XRD trace, after which a calibration function was applied (Matulis and Taylor, 1992) to compensate for the effects of the Bragg-Brentano goniometer geometry on the X-ray diffraction pattern.

Operation of Siroquant involved interactive adjustment and best-fit matching of the XRD profiles for the individual minerals in the task file to the observed X-ray powder diffraction pattern for the sample under analysis. Some parameters were progressively refined in order to fit more precisely the mineral’s profile in the sample XRD pattern, including overall intensities (scales) of the individual mineral phases, unit-cell dimensions, linewidths, and preferred orientation for the minerals, as well as the zero setting of the diffractometer. At each stage of the process, weight percentages of the different minerals were calculated together with errors for each mineral phase and the overall goodness of fit (chi2 value) between the observed and computed profiles.

The distribution of peak heights in several minerals was inconsistent with the standard mineral pattern, although a match was obtained for the key peak positions. Siroquant was used to refine the standard pattern for such minerals based on the March Function preferred-orientation correction (Dollase, 1986), and this also adjusted the mineral percentages in the analysis accordingly.

The results of the Siroquant analysis represent the final output from each task, when the best possible fit had been obtained between the observed and calculated XRD

88 patterns. Figure 4.8 illustrates diffractograms from the Siroquant analysis for one sample (SR 15), with the analysis result for SR 15 presented in Table 4.11. The analysis results for all samples are presented in Table 4.12. The global chi2 value represents an estimate of the overall goodness of fit for the analysis, as indicated by Taylor (1991). Ideally, the global chi2 value should approach unity for a perfect fit between the measured and interpreted patterns. In practice, however, is usually greater than 1. Chi2 values obtained for the present study ranges between 3.72 and 9.99, with the most values around 5 or 6.

Observed Pattern

4000 3000 2000

Counts 1000 0 0 102030405060 Degrees 2-theta Calculated Pattern

4000 3000 2000

Counts 1000 0 0 102030405060

DifferenceDegrees Pattern 2-theta

1000

0 0 102030405060 Counts -1000 Degrees 2-theta

Figure 4.8. X-ray diffraction data from SR 15, showing the observed diffractogram (top), the synthetic diffractogram obtained from Siroquant analysis (middle), and the difference between them (bottom)

89 Table 4.11. Siroquant result for typical oil shale sample (SR 15)

Contrast Corrected Weight % Phase Weight% Error of Fit Quartz 17.8 0.7 Kaolinite 30.2 1.3 Illite 5.9 1.6 Mixed layer illite-smectite 4.4 1.4 Chlorite 15.0 1.1 Albite 8.9 1.9 Orthoclase 2.0 1.3 Calcite 15.8 0.7 Pyrite 0.0 0.4 Task: C:\APD\Fatimah2\01604.tsk Global Chi^2: 8.33

4.2.3. Results

Table 4.10 shows that the Sangkarewang Formation sediments consist mainly of quartz, feldspar, carbonates and a range of clay minerals, together in some cases with minor proportions of sulphide minerals. Some samples are dominated by quartz and feldspar, but others, representing impure lacustrine limestones, are dominated by carbonate minerals.

The proportion of quartz in the sediments, especially the shaly materials, is relatively consistent (10-30%) throughout the succession. Feldspar, identified mainly as albite but including some orthoclase, is relatively abundant (10-25%) in the lower part (Sumpahan and Santur Facies) of the Sangkarewang Formation, but only a rare component (<3%) of the shales in the upper part of the sequence (Ampang Nago Facies).

With the exception of some very carbonate-rich samples (e.g. SR-17 and SR- 25), kaolinite typically makes up between 15 and 30% of the samples studied. Illite, smectite, interstratified illite-smectite and chlorite are abundant in the samples from the lower and middle parts of the sequence, but less abundant, relative to kaolinite, in the upper part of the succession. The coaly shale in the upper part of the Sangkarewang Formation (Sample SR-11) is unusual, relative to the other samples, in that it has a mineral fraction consisting almost entirely of carbonate components.

90 Table 4.12. Quantitative percentages of minerals identified in samples studied using powder XRD and Siroquant

Sample Location Lithology Facies Qtz Albite OrthIllite Kaol Smec I/S Chl Pyrite CalciteAnk SidGyp Laum SR 28 Sawahlunto Coal Sawahlunto Fm SR 11 Sumpahan River Coaly shale Ampang Nago 0.1 70.1 29.8 SR 3 Sumpahan River Shale Ampang Nago 12.0 0.7 9.2 15.3 6.8 3.4 52.6 SR 35 Sumpahan River Shale Ampang Nago 15.0 1.1 0.4 4.2 30.8 1.4 6.6 3.3 34.7 2.5 SR 32 Sumpahan Rive Shale Ampang Nago 21.1 2.5 0.2 15.0 30.4 1.3 6.5 1.4 2.1 9.8 4.5 5.2 SR 15 Malakutan River Shale Santur 17.8 8.9 2.0 5.9 30.2 4.4 15.0 15.8 SR 17 Malakutan River Shale in breccia Santur 17.2 12.8 0.7 2.5 3.0 0.4 1.5 61.8 SR 21 Kolok Sandstone Santur 41.3 5.2 13.7 17.1 7.1 3.7 1.8 10.1 SR 25 Kolok Sandstone Santur 18.0 8.8 1.0 1.9 5.5 0.8 3.2 60.7 SR 5 Talawi Shale Sumpahan 14.6 15.3 6.4 15.9 21.9 9.0 5.0 11.8 SR 8 Talawi Sandstone Sumpahan 12.3 17.7 3.1 19.2 17.0 10.3 14.9 5.5 SR 14 Sipang River Shale Sumpahan 16.8 11.5 0.8 17.6 25.6 1.8 10.9 7.7 7.4 SR 7 Sipang River Shale Sumpahan 15.9 10.1 1.5 12.3 25.5 14.9 19.1 0.4 0.3 SR 19 Sipang River Shale Sumpahan 25.7 11.4 2.0 9.8 20.5 2.5 6.8 5.9 15.5 SR 6 Sipang River Shale Sumpahan 30.5 11.4 2.9 6.0 31.4 7.0 3.6 7.2 SR 26 Sipang River Sandstone Sumpahan 27.0 22.6 4.5 10.0 16.4 10.2 2.4 7.0 SR 42 Ampang Nago Sandstone Sumpahan 18.4 23.7 4.6 16.7 17.9 3.7 8.3 6.7 SR 37 Ampang Nago Shale Sumpahan 14.9 10.7 22.9 25.3 2.3 3.4 0.1 20.4 SR 43 Padang Ganting Sandstone Sumpahan 23.4 11.9 3.4 5.0 16.5 5.2 24.9 0.4 9.4

Qtz = quartz; Orth = orthoclase; Kaol = kaolinite; Smec = smectite; I/S = interstratified illite/smectite; Chl = chlorite; Ank = ankerite; Sid = siderite; Gyp = gypsum; Laum = laumontite

91 Except for SR-11, which also contains ankerite, and SR-32, which contains a small proportion of siderite, calcite is the only carbonate mineral identified in the samples by the XRD study. High proportions of calcite (up to 50%) commonly occur in shales from the middle and upper parts of the Sangkarewang Formation (Ampang Nago and Santur Facies), whereas samples from the lower part (Sumpahan Facies) tend to have somewhat lower calcite contents (mostly less than 10%). Pyrite, where present, also tends to be more common in the shales from the middle and upper parts of the sequence.

The mineralogical data suggest that a greater proportion of detrital sediment, rich in feldspar and chlorite and probably derived from relatively unweathered sources, was introduced into the basin in the early stages of Sangkarewang deposition. A sandstone containing abundant chlorite, along with the zeolite mineral laumontite, is also present in the lower part of the succession, suggesting derivation from an altered volcanic source material. The chlorite and feldspar appear to have become less abundant as sediment components in the later stages of the unit’s history, possibly due to changes in provenance or increased weathering in the source area. The increase in carbonate deposition in the upper part of the unit, along with the common presence of pyrite, suggests an increase in authigenic sedimentation in the later stages of deposition, consistent with a deeper and more stable lacustrine environment and a more quiescent tectonic setting.

4.3. Evaluation of Chemical and Mineralogical Data

4.3.1. Data from XRF Analysis Graphic plots were made to evaluate correlations among particular elements (Figure 4.9 to 4.21), based on the XRF data for the rock samples. These plots were used to investigate variations and relationships and to test the integrity of the chemical data.

92 80 70 60 50 40 LoI 30 20 10 0 0 20406080 SiO2

Figure 4.9. Correlation between SiO2 and loss on ignition (LOI) for samples from the Sangkarewang Formation

CaO - SiO2 70 60 50 40 30 SiO2 (%) 20 10 0 0 5 10 15 20 25 30 CaO (%)

Figure 4.10. Correlation between CaO and SiO2 for samples from the Sangkarewang Formation

CaO - LOI 35

15 LOI (%) LOI 10

0 0 5 10 15 20 25 30 CaO (%)

Figure 4.11. Correlation between CaO and LoI for samples from the Sangkarewang Formation

3.5 3.0 2.5 2.0

K2O 1.5 1.0 0.5 0.0 0 5 10 15 20 25 Al2O3

Figure 4.12. Correlation between Al2O3 and K2O for samples from the Sangkarewang Formation

1.2 1.0 0.8 0.6 TiO2 0.4 0.2 0.0 0 5 10 15 20 25 Al2O3

Figure 4.13. Correlation between Al2O3 and TiO2 for samples from the Sangkarewang Formation

Na2O - SO3

3.5

2.5

SO3 (%) 1.5

0.5

0 00.511.522.533.5 Na2O (% )

Figure 4.14. Correlation between Na2O and SO3 for samples from the Sangkarewang Formation

CaO - MgO

2.5

1.5

MgO (%) MgO 1

0.5

0 0 5 10 15 20 25 30 CaO (%)

Figure 4.15. Correlation between CaO and MgO for samples from the Sangkarewang Formation

500

400

300

PbO 200

100

0 0 500 1000 1500 2000 CeO2

Figure 4.16. Correlation between CeO2 and PbO for samples from the Sangkarewang Formation

300 250 200 150 U3O8 100 50 0 0 500 1000 1500 2000 CeO2

Figure 4.17. Correlation between CeO2 and U3O8 for samples from the Sangkarewang Formation

300 250 200 150 U3O8 100 50 0 0 500 1000 1500 ThO2

Figure 4.18. Correlation between ThO2 and U3O8 for samples from the Sangkarewang Formation

2000 1500

1000 CeO2 500 0 0 100 200 300 400 500 600 ZrO2

Figure 4.19. Correlation between ZrO2 and CeO2 for samples from the Sangkarewang Formation

1400 1200 1000 800

ThO2 600 400 200 0 0 100 200 300 400 500 600 ZrO2

Figure 4.20. Correlation between ZrO2 and ThO2 for samples from the Sangkarewang Formation

96 300 250

200 150 U3O8 100

50 0 0 200 400 600 ZrO2

Figure 4.21. Correlation between ZrO2 and U3O8 for samples from the Sangkarewang Formation

Figures 4.9 to 4.11 show correlations between loss on ignition (LOI) and selected elements. Because of the high LOI in the coaly material of sample SR 11 caused by the abundant organic matter, this sample was left out of the plots in order to focus on the other materials.

The plot of LOI against SiO2 (Figure 4.9) shows a negative correlation. This indicates that carbonates and organic matter, both of which would contribute significantly to the LOI, are more abundant in the rocks with low silicate mineral contents (such as quartz and the clay minerals).

The plot of SiO2 against CaO (Figure 4.10) also shows a negative correlation. This probably reflects the chemical variation between carbonate-rich and quartz-clay rich sediments. Similarly, the plot of LOI against CaO (Figure 4.11) shows a relatively strong positive correlation, consistent with the LOI being dependent at least in part on the calcium carbonate content.

The positive correlation between K2O and Al2O3 (Figure 4.12) is consistent with the potassium occurring mainly in Al-bearing minerals, such as illite, mica, and any K- feldspar components. The positive correlation between TiO2 and Al2O3 (Figure 4.13) is more difficult to explain, but may represent Ti occurring in or attached to clay minerals such as kaolinite, as has been suggested for Gunnedah Basin coals by Ward et al. (1999).

The plot of Na2O against SO3 (Figure 4.14) shows a significant negative relationship, especially at low Na2O levels as found in the upper part of the Sangkarewang Formation (SR 11, the coaly shale sample has been excluded). This may indicate that Na plays a part in retention of SO3 in the calcined rock samples. The plot of CaO against MgO (Figure 4.15) shows no particular correlation between these elements. This may indicate that the carbonate minerals do not have any significant Mg in their lattice, and that the Mg in the samples mainly occurs in the clay minerals.

Among the trace elements, cerium (as CeO2) and lead (PbO) tend to increase from the lower to the upper parts of the Sangkarewang Formation (Table 4.4).

Zirconium (as ZrO2) on the other hand, decreases up the Sangkarewang sequence.

The overall proportions of CeO2, PbO and U3O8 show a positive relationship to each other (Figures 4.16 and 4.17). Thorium (ThO2) and uranium (U3O8) also have a strong positive relationship (Figure 4.18). CeO2, ThO2, and U3O8, however, each show a broad but significant negative relationship to the ZrO2 content of the rock samples (Figures 4.19 to 4.21).

4.3.2. Carbonate Carbon and Organic Carbon

Correlations between the proportion of carbonate carbon in the samples determined by elemental analysis (Table 4.5) and the proportion of calcite indicated by XRD (Table 4.12) are indicated in Figure 4.22. The coaly shale sample (SR-11) was not included in this plot, due to difficulties in allowing for its high organic carbon content. The data points show a high correlation coefficient (R2 = 0.95), and plot close to the line representing the values in each case expected from chemical stoichiometry. This suggests again that the XRD quantifications for the oil shale samples are consistent with independent chemical data.

98 CO3 Carbon - Calcite 100 y = 9.26x - 2.08 R2 = 0.95 80

Calcite by XRD (%) 20

0 024681012 CO Carbon by LECO (%) 3 Figure 4.22. Correlation between carbonate carbon and calcite as determined by XRD

A more scattered but nevertheless discernable correlation (R2 = 0.53) is noted in Figure 4.23 between the organic carbon content of the oil shales and the calcite content. The coaly shale sample (SR-11), with 40% organic carbon (Table 4.5) was not included in this plot, partly because it represents a different lithology to the other shale samples. Sample SR-17, which was taken from a calcareous shale fragment contained within a breccia unit of the Sangkarewang sequence or an interfingering horizon of the Brani Formation, was also not included in the correlation. This sample has a much lower organic carbon content than the oil shales otherwise represented in the sequence, and again appears to represent a different rock type.

Organic Carbon - Calcite 70

SR-17 60

50 y = 4.70x - 4.57 40 R2 = 0.53

20 Calcite by XRD (%) 10

0 024681012 Organic Carbon by LECO (%) Figure 4.23. Correlation between organic carbon and calcite content

4.3.3. Comparison of XRD and XRF Data

Comparison between the chemistry of the materials as determined by X-ray fluorescence and the chemistry inferred from the quantitative mineralogy identified by X-ray diffraction was also carried out in present study. This was intended to evaluate the relationships between the mineral percentages and the overall chemical composition of the samples, as well as to obtain an independent check on the Siroquant analysis results. This type of comparative study has been discussed in a number of other papers (e.g. Ward et al, 2001; Ruan and Ward, 2000; Ward et al, 1999; Ward and Taylor, 1996), where it has acted to confirm the consistency of Siroquant results for other materials. It is also included in a paper derived from the present study by Fatimah and Ward (2008).

The chemical composition of the mineral assemblage determined by Siroquant analysis was calculated for each sample from the relative proportions of the minerals indicated by the X-ray diffraction data and their expected chemical composition based on the chemical stoichiometry of each mineral. For instance, the chemical composition of kaolinite was calculated as follows:

The kaolinite formula is Al4[Si4O10](OH)8, which means it composed of 2

Al2O3, 4 SiO2 and 4 H2O units. The molecular weights for Al2O3, SiO2 and H2O are 101.96, 60.08 and 18.015 respectively. Hence, the total molecular weight for kaolinite would be:

2 Al2O3 = 2 x 101.96 = 203.92

4 SiO2 = 4 x 60.08 = 240.32

4 H2O = 4 x 18.015 = 72.06 Total 516.30

The percentage of each major oxide in kaolinite can be calculated as follows: 203.92 Al2O3: x 100% = 39.49% 516.30

100 Using the same calculation, the proportion of each other major oxide can be calculated and it can be concluded that kaolinite is composed of 39.49% Al2O3, 46.55% SiO2 and

13.96% H2O.

The oxide composition of each other mineral in the samples was estimated in a similar way. Using a Microsoft Excel spreadsheet, the oxide composition of each rock sample was then estimated from the percentage of each mineral indicated by Siroquant, multiplied by the respective oxide percentages for that mineral (Table 4.13). The total of these individual calculations was then determined, using the spreadsheet, to give the total inferred percentage of each oxide in the mineral mixture. As an example, Table 4.14 illustrates the calculation of the oxide composition of sample SR 5. Table 4.13. Calculation of oxide composition from mineral indicated by Siroquant

Mineral % SiO2 Al2O3 MgO CaO Na2O K2O H2O CO2 Total Quartz n n total Quartz Kaolinite n n x 0.465 n x 0.395 n x 0.14 total Kaolinite Smectite n n x 0.6279 n x 0.2779 n x 0.0184 n x 0.0127 n x 0.0141 n x 0.049 total Smectite Illite n n x 0.5023 n x 0.3606 n x 0.0908 n x 0.0463 total Illite Chlorite n n x 0.3358 n x 0.3799 n x 0.1502 n x 0.1341 total Chlorite Albite n n x 0.687 n x 0.195 n x 0.118 total Albite Orthoclase n n x 0.647 n x 0.184 n x 0.169 total Orthoclase Calcite n n x 0.56 n x 0.44 total Calcite Total 0.00 total each oxide total mineral Normalised total each oxide / total mineral x 100 n : mineral percentage indicated by Siroquant

Table 4.14. Example of oxide composition calculation for SR 5

Mineral Percent SiO2 Al2O3 MgO CaO Na2O K2O H2O CO2 Total Quartz 12.3 12.3 12.3 Kaolinite 11.6 5.394 4.582 1.624 11.6 Smectite 11.4 7.15806 3.16806 0.20976 0.1448 0.1607 0.5586 11.4 Illite 22.5 11.3018 8.1135 2.043 1.0418 22.5 Chlorite 2.8 0.94024 1.06372 0.42056 0.3755 2.8 Albite 22.2 15.2514 4.329 2.6196 22.2 Orthoclase 9.4 6.0818 1.7296 1.5886 9.4 Calcite 7.7 4.312 3.388 7.7 Total 99.90 58.43 22.99 0.63 4.46 2.78 3.63 3.60 3.39 99.90 Normalised 100.00 58.49 23.01 0.63 4.46 2.78 3.64 3.60 3.39 100.00

Comparisons between the chemistry inferred from the mineral proportions indicated by Siroquant (Table 4.12) and that determined directly by chemical analysis (Table 4.3) was carried out in this study using the method described above. Nineteen samples from the Sangkarewang deposit were included in this comparative study. Unlike the chemical analysis, the Siroquant data were based on the assumption that the rock samples consisted only of mineral phases, without any organic matter content.

101 Hence, the sample with the high organic carbon content (SR 11) was not included in this comparison.

The comparisons for each major oxide are given in Figures 4.24 to 4.32, prepared using Microsoft Excel software. Each set of data was also evaluated by linear regression analysis, again using the Excel software system.

The relationship identified by the regression analysis has a formula expressed by: y = ax + b where a is the slope of regression line, and b is the intercept on the y axis

The regression equation in each case is shown on the respective graphic plot, along with the regression line and the coefficient correlation (R2). A diagonal line is also shown, corresponding to the location of the points if a perfect correlation were to be obtained. A perfect correlation would have a = 1, b = 0 and R2 = 1.00 from this regression analysis (Ruan and Ward, 2002; Ward et al, 1999).

Figures 4.24 to 4.32 represent the results of such plots for the principal oxide components inferred from Siroquant and determined directly by chemical analysis.

SiO2 70

y = 0.97x + 4.30 60 R2 = 0.85

30 from XRD (%) 2 20 SiO 10

0 0 10203040506070

SiO2 by XRF (%)

Figure 4.24. Comparison between SiO2 obtained from chemical analysis (XRF) and SiO2 deduced from the Siroquant analysis

102 The plot for SiO2 (Figure 4.24) has a regression line with a slope close to 1.0

(0.9287), and the points all plot parallel to the diagonal equality line. The plot for SiO2, however, lies somewhat above the equality line, suggesting a systematic over-estimation of the SiO2 content inferred from Siroquant data relative to the proportion directly determined by chemical analysis. This may reflect a slight over-estimation of the quartz percentage by Siroquant. Over-estimation of SiO2 by Siroquant is accompanied by under-estimation of MgO, K2O and loss on ignition (see below).

Al2O3 30 y = 1.33x + 0.48 2 25 R = 0.86

15 from XRD (%) from 3 10 O 2

Al 5

0 0 5 10 15 20 25 30

Al2O3 by XRF (%)

Figure 4.25. Comparison between Al2O3 obtained from chemical analysis (XRF) and Al2O3 deduced from the Siroquant analysis

The points for Al2O3 also lie above the equality line (Figure 4.25), indicating a high Al2O3 content inferred from the Siroquant data relative to the proportion directly determined by chemical analysis. This is, however, probably because spreadsheet for the Siroquant evaluation assumed that the illite and illite-smectite were the Al end- members, and hence devoid of Fe in the lattice structure. Illite, however, may also have significant proportions of Fe and Mg (Deer et al, 1992; Moore and Reynolds, 1997). Substitution of Fe for Al in the illite lattice and in the illite component of the illite- smectite would increase the estimated percentage of Fe2O3 and decrease the proportion of Al2O3, relative to the mineral compositions used in the comparison process.

103 If the illite in the samples is an iron-rich illite, with some Al replaced by Fe, and if there are no other Fe-bearing minerals in the samples studied (only a small proportion of pyrite occurs in some samples), then the bulk of the Fe must also be present in the illite. To confirm this, Al2O3 and Fe2O3 were considered together in the one plot (Figure 4.26), which showed a very good correlation.

Al2O3 + Fe2O3 30

y = 1.02x + 0.35 25 R2 = 0.89

from XRD(%) 15 3 O 2 10 + Fe 3

O 5 2 Al 0 0 5 10 15 20 25 30

Al2O3 + Fe2O3 by XRF (%)

Figure 4.26. Comparison between Al2O3 and Fe2O3 obtained from chemical analysis (XRF) and Al2O3 and Fe2O3 deduced from the Siroquant analysis

Substitution of Fe for Al in the illite lattice and in the illite component of the illite-smectite would increase the estimated percentage of Fe2O3 in the calculation from the Siroquant data. This would improve the correlation between the calculated and actual values for these otherwise weakly correlated constituents. It would also proportionally decrease the Al2O3 percentage in the Siroquant calculation. Such a decrease would make the results more consistent with an over-estimation of Al2O3, as found in Figure 4.26.

The regression equation for CaO has a slope close to 1.0, a high correlation coefficient (r2 = 0.9387) and a relatively low intercept value (Figure 4.27). The correlation line for CaO plots close to the diagonal equality line, indicating equality and suggesting compatibility between the Siroquant determinations and the chemical data. Calcium occurs mainly in calcite, which is present to some extent in almost all rock

104 samples. In this comparison, CaO shows a relatively good level of agreement between the directly determined by chemical analysis values and the inferred proportion from the Siroquant data. Plot of the percentage of calcite as determined by XRD and Siroquant against the percentage of carbonate carbon determined from the LECO (Figure 4.28) also shows a relatively positive correlation. An anomaly occurs on SR 43, which has laumontite mineral; however, as CaO would also be in the laumontite component.

CaO 50

y = 1.35x - 1.87 SR-11 R2 = 0.84 40

CaO from XRD (%) CaO from 10

0 0 1020304050 CaO by XRF (%)

Figure 4.27. Comparison between CaO obtained from chemical analysis (XRF) and CaO deduced from the Siroquant analysis

CO3 Carbon - Calcite 100 y = 9.26x - 2.08 R2 = 0.95 80

Calcite by XRD (%) 20

0 024681012

CO3 Carbon by LECO (%)

Figure 4.28. Plot of calcite determined by Siroquant against carbonate carbon determined by the LECO analyzer

105 The Na2O percentage estimated from the Siroquant data (Figure 4.29) is generally close to the actual Na2O percentage indicated by chemical analysis. There is, however, a trend suggesting over-estimation of Na2O from the X-ray diffraction analysis. This may reflect an over-estimation in the stoichiometric calculation of Na. Na mainly exists in plagioclase, which the Siroquant has identified as albite. The plagioclase may, however, also contain some Ca, eg as andesine. In reality there may thus be less Na and some Ca in the plagioclase of the samples studied. This probably explains the gap, especially at high Na2O levels. It is not accompanied by a similar gap in the CaO comparison, however, because of the much higher proportion of CaO due to the carbonate minerals present.

Na2O 3.0 y = 0.81x + 0.30 2 2.5 R = 0.68

2.0

1.5

1.0 O from XRD (%) 2

Na 0.5

0.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0

Na2O by XRF (%)

Figure 4.29. Comparison between Na2O obtained from chemical analysis (XRF) and Na2O deduced from the Siroquant analysis

The proportion of K2O inferred from the Siroquant data shows a rather scattered correlation with the K2O content measured by direct determination (Figure 4.30). This may be partly caused by uncertainty in estimating the K2O proportion in the clay minerals. The K2O content could be derived from mica as well as from illite. The mica may be more K-rich. Other illite may be partly degraded, and have less potassium than the illite composition used in the Siroquant calculation. Therefore the K2O proportion obtained from chemical analysis would be higher in some cases and lower in others, relative to the K2O percentage estimated from the Siroquant data.

106 No significant relationship was found between the percentage of MgO indicated by chemical analysis and the percentage of magnesium minerals indicated as separate phases by the Siroquant (Figure 4.31). The poor correlation may be a function of the low MgO proportion present. Mg may occur in chlorite, other clays (illite and illite- smectite), calcite, as well as dolomite. Under-estimation of MgO from the Siroquant data may be partly because of uncertainty of the source of the MgO.

K2O 3.0

y = 1.10x - 0.35 2.5 R2 = 0.84

2.0

1.5

1.0 O from XRD (%) 2 K 0.5

0.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0

K2O by XRF (%)

Figure 4.30. Comparison between K2O obtained from chemical analysis (XRF) and K2O deduced from the Siroquant analysis

MgO 5 SR-11 y = 2.10x - 2.04 2 4 R = 0.58

MgO from XRD (%) 1

0 012345 MgO by XRF (%)

Figure 4.31. Comparison between MgO obtained from chemical analysis and MgO deduced from the Siroquant analysis

107 The loss on ignition (LOI) was determined by heating the dried samples to 1050oC as part of the chemical analysis process. The LOI represents a combination of the structural OH groups which were lost from the clay minerals, the CO2 lost from the carbonates and the destruction of the organic matter during the LOI determination. Although there is overall quite a good correlation (Figure 4.32), most of the LOI proportions are slightly higher than the total percentage of structural OH (as H2O) and

CO2 inferred from the Siroquant data. The reason for this under-estimation is probably because the organic matter content of the samples was not taken into account in the Siroquant evaluation. The chemical analysis includes the organic matter proportion in its calculation whilst the chemistry inferred from the Siroquant is based on the sample without considering the presence of organic matter.

LOI 100

y = 1.16x - 2.95 SR-11 2 80 R = 0.96

60 O (from XRD) XRD) (from O

2 40 + H 2 20 CO + Organic Carbon (%) Carbon Organic +

0 0 20406080100 LOI by XRF (%)

Figure 4.32. Comparison between Loss on Ignition obtained from chemical analysis (XRF) and H2O + CO2 deduced from the Siroquant analysis

Overall, the comparison between the chemistry inferred from the Siroquant data and that obtained by direct chemical analysis shows a good level of consistency, confirming the value of the Siroquant as a basis for estimating mineral percentages in the Sangkarewang materials.

108 CHAPTER 5

ORGANIC AND INORGANIC PETROLOGY OF THE SANGKAREWANG OIL SHALE DEPOSIT

5.1. Sedimentary Petrography

Petrography is the description and classification of rocks (Moorhouse, 1959). It covers the systematic and descriptive aspects of rocks, as well as the natural history and origin of rocks and rock masses. Petrographic studies of sedimentary strata (sedimentary petrography) is mainly carried out in thin section. Petrography of polished sections is more commonly used for ore deposits (mineragraphy) and for organic petrology studies.

5.1.1. Background

Sedimentary petrography may include analysis of both depositional and diagenetic fabrics from rock thin section microscopy (Harwood, 1988). Such studies may cover mineralogical composition, grain size distribution and sediment provenance, as well as fabric studies and determination of the sequence of diagenetic events.

Study of rocks in thin section provides information regarding the mineralogy of the rock, including the proportion of the various minerals, as well as the texture. Although the proportion of the various minerals can also be determined by other methods, such as X-ray diffraction analysis (e.g. Ward et al., 1999), thin section study can provide information regarding rock texture and the modes of mineral occurrence, features that may be as important as the mineralogy itself.

Even if point count techniques are used, microscopic examination inherently does not provide a full mineralogical analysis of the material. Components such as rock fragments and matrix in particular consist of fine-grained, closely intergrown mineral

109 mixtures; the minerals in them cannot be identified, much less evaluated on a quantitative basis, using thin section studies. The fine grained nature of shales also makes thin section study difficult. Many shale constituents are not readily resolved under the microscope, so they cannot be identified by the usual optical means (Pettijohn, 1975).

According to Moorhouse (1959), shale is an unmetamorphosed, very fine argillaceous rock with a distinct fissility parallel to bedding. Argillaceous rocks in the unmetamorphosed condition are composed of several mineralogical fractions, and the mineralogy of these rocks is best considered according to these phases: the silty fraction, the clay fraction, and the precipitated fraction. The silty fraction is made up of chips of quartz, feldspar, muscovite, and biotite. The clay fraction is usually composed of illite, kaolinite and some associated minerals such as chlorite, glauconite, montmorillonite and nontronite. Illite in rock thin section, however, is indistinguishable from fine-grained mica (sericite).

Some shales contain carbonaceous material as a very abundant constituent, especially, for example, oil shales. The carbonaceous material is sometimes difficult to distinguish in thin section from tiny grains of opaque minerals such as magnetite and pyrite. Polished section studies (see below) usually provide a better indication of the types of organic matter present. The precipitated fraction is commonly composed of carbonates such as calcite, dolomite or siderite.

Moorhouse (1959) also noted that some shales display a distinct aggregate structure in thin section, with the interstices between the aggregates filled by silty material and individual clay flakes. The aggregates probably represent flocculated masses of clay. Many shales in thin section also display bedding (lamination), as well as fissility. This could represent layers of relatively high clay content alternating with silty layers, as well as layers of calcareous and/or organic debris or layers of fine-grained precipitated carbonate alternating with shaly or silty laminae.

110 5.1.2. Analytical Methods

Standard rock thin sections of 30m nominal thickness were prepared for the study, bonded to glass slides by epoxy-based adhesives. The methods used to make thin sections of rock sample are described in several textbooks, such as Moorhouse (1959) and Miller (1988).

Observation of rock thin sections was carried out using a polarizing microscope. The visible features were observed, including grainsize and texture, as well as mineral composition, using objective lenses with 20X and 40X magnifications. Images were taken by an ISSCO-CCD colour camera using Snappy 2.1 software connected to a Leitz HM-Pol polarizing microscope.

5.1.3. Results

Ten rock samples were prepared as thin sections, representing typical variations in the lithology of the rocks in the Talawi area. These include granite, breccia, sandstone and siltstone, as well as mudstone. Five of the samples, mainly sandstone and siltstone, were taken from the Sangkarewang Formation.

As mentioned in the previous chapter, the Sangkarewang Formation in the Talawi area can be divided into three parts: the lower, middle and upper parts. Claystone and shale with thin laminations of sandstone dominate the upper part of the Sangkarewang Formation. The fine-grained nature of these sediments made them difficult to prepare as thin sections.

Thin sections of samples from the lower part of the Sangkarewang Formation show layers alternating between silt and fine sand size, with quartz as the main mineral present. Other minerals associated with the quartz are biotite, plagioclase feldspar and chlorite (Figure 5.1). A high proportion of biotite occurs in sample SR 6 (more than 10% in one section), whilst other samples only have small biotite proportions (SR 8, for example, contains less than 5% biotite). The silty layers are dominated by calcite and carbonate minerals. Rock fragments in the sediments are poorly sorted, with

111 predominantly angular grains. Minor proportions of sub-rounded grains, however, are also present. Well-crystallized quartz, and an abundance of plagioclase and biotite, indicate that these rocks were derived from igneous sources (possibly granite), which were transported over a short distance (i.e. the sediment is close to its source rock).

Qz Biotite

Figure 5.1. Thin section of sandstone from Talawi area (SR 16) showing quartz, feldspar and biotite particles in open (left) and crossed polars (right).

One sandstone sample from Padang Ganting area (SR 43) is composed of chlorite, biotite, plagioclase, iron oxide and amphibole (Figure 5.2). Such interpretation is confirmed by the XRD results from the same sample (Chapter 4), which show albite, quartz and abundant chlorite, along with the zeolite mineral laumontite. These features suggest derivation from an altered volcanic source material.

The middle part of the Sangkarewang Formation is characterised by somewhat equal proportions of claystone, shale and sandstone. Thin sections of the sandstone from this part of the sequence show that it is composed mainly of quartz cemented by carbonate precipitates. In one sample (SR 21), carbonate cement is abundant in thin section (Figure 5.3), with quartz forming the main framework grains. This is consistent with the XRD results for the same sample, which gave quartz and calcite as the main minerals. Other minerals are plagioclase, chlorite and other clay minerals, together with some opaque minerals (possibly iron oxide or iron sulphide).

112 Biotite

Figure 5.2. Altered plagioclase and biotite in sandstone from the lower Sangkarewang sequence (SR 43), open polars (left) and crossed polars (right).

Figure 5.3. Thin section of SR 21 (open polars) dominated by carbonate.

113 5.2. Organic Petrology

5.2.1. Background

Organic petrology is the microscopic study of organic matter in rocks using either transmitted or incident white light or blue-violet incident-light in fluorescence- mode. It encompasses aspects such as maceral analysis, vitrinite reflectance measurement and studies of maceral fluorescence (Hutton, et al., 1980), as well as chemical evaluations such as carbon and oxygen determination in macerals using electron microprobe techniques (Bustin et al., 1993).

Oil shale consists of mineral matter and organic matter. Optical examination of oil shale kerogens indicates that some of them are almost entirely made of algal remains, whereas others are an admixture of amorphous organic matter with a variable proportion of identifiable organic remnants. Organic particles in oil shales sometimes cannot be readily classified, and their origin is often uncertain (Hutton and Cook, 1980).

The organic matter in oil shale may include members of three maceral groups: vitrinite, liptinite and inertinite. These are discussed more fully in Chapter 1. As indicated in Chapter 1, the macerals of the liptinite group are the most significant organic components in oil shale; provided the rank is in the appropriate range these give significantly higher oil yields than the other maceral groups. The different types of liptinite that may be present, as well as their use in oil shale classification, are discussed in Chapter 1. Although the organic matter in oil shales is dominated by liptinite macerals, small proportions of vitrinite and inertinite may also be present. Vitrinite in oil shales mostly occurs as tiny dispersed grains. Although less significant with respect to oil yield, the vitrinite provides a useful basis for determining the maturity of the organic matter through measurement of the vitrinite reflectance.

Vitrinite reflectance measurement is a technique used to characterise the rank of coal and the maturity of petroleum source rocks, and is a very popular tool among coal and petroleum geologists. It has been regarded as a source rock maturity parameter for a long time by organic petrologists. The reflectance of vitrinite, however, sometimes

114 shows anomalies relative to the normally expected values. These anomalies have been discussed in several papers, such as those of Gurba and Ward (1998); Gentzis and Goodarzi (1994); Mukhopadhyay (1994); Kalkreuth (1982); and Hutton and Cook (1980).

Gurba and Ward (1998) studied the vitrinite reflectance anomalies in some Permian coals of the Gunnedah Basin, Australia. They observed that the vitrinite reflectance values were lower than expected from the relevant burial depths due to marine influence. In the presence of igneous intrusions, on the other hand, the vitrinite reflectance showed a higher value than the normal vitrinite reflectance. The value of vitrinite reflectance also tended to be higher in the variety referred to as pseudovitrinite.

In other sedimentary rocks, such as oil shale, the vitrinite reflectance value can also be affected by the abundance of liptinite macerals present. Hutton and Cook (1980), for example, noted that the mean maximum vitrinite reflectance of some Australian oil shales is significantly lower in the presence of alginite. It is thought that the lower reflectance values of vitrinite associated with alginite may be related to the vitrinite type, as well as to the physico-chemical or geochemical changes that occur during diagenesis or later in the coalification processes.

Kalkreuth (1982) has studied some coal samples from British Columbia, Canada. He observed that the total proportion of associated liptinite controlled the vitrinite reflectance value, and that the vitrinite reflectance gradually decreases with increases in liptinite content. This effect was interpreted as being caused by diffusion of bituminous substances out of the liptinite macerals into the surrounding vitrinite.

Similarly, Gentzis and Goodarzi (1994) noted that suppression of vitrinite reflectance in coal or sediments is usually associated with high proportions of liptinite macerals, such as occur in oil shale.

Mukhopadhyay (1994) observed that the vitrinite reflectance of marine shales or lacustrine coals and shales within the oil window is often much lower (0.15 to 0.50%) compared to the humic coals that overlie or underlie the shales. He reviewed several

115 factors that can affect vitrinite reflectance measurement and result in the suppression of vitrinite reflectance. These are: 1. Lithological variations and associated differences in thermal conductivity and heat capacity. 2. The formation of perhydrous vitrinite or vitrinite-like macerals due to lipid incorporation within the biopolymer derived from lignin, cellulose or tannin. 3. The impregnation of vitrinite with generated bitumen or incorporation of migrated oil into the vitrinite. 4. An abundance of liptinite macerals in a vitrinite-poor source rock. 5. Variable degrees of bacterial activity in the sediment. 6. Sample contamination due to cavings derived from the younger horizons above, or from mixing with lignitic drilling mud additives.

In general, vitrinite reflectance anomalies are manifested in higher vitrinite reflectance than normally expected (e.g. with pseudovitrinite), or anomalously low (suppressed) vitrinite reflectance values (e.g. due to marine influence). In oil shales, the abundance of liptinite macerals, which are hydrogen-rich materials, may be associated with development of perhydrous vitrinite, which has a suppressed (anomalously low) reflectance value for its burial depth and thermal history.

5.2.2. Analytical Methods

Fifteen rock samples from the study area were prepared as polished sections for maceral analysis and vitrinite reflectance measurement. To prepare the polished sections, the rock samples were cut into small chips, mounted in an epoxy resin, and polished according to standard techniques. Maceral analysis was carried out using a Zeiss Axioplan microscope (Figure 5.4) with an Epiplan ‘Neofluar’ x50 objective under oil immersion. Macerals were identified following the maceral classification recommended by the International Committee for Coal Petrology (1971). Vitrinite and inertinite groups were identified using white light whilst liptinite group macerals were identified using blue light to observe their fluorescence properties.

116 Mean maximum vitrinite reflectance in oil (n oil = 1.518 at 23oC) was measured using a Zeiss MSP21 – Microscope System Processor, using a glass standard with a reflectance 0.51%. Twenty reflectance measurements were taken on each sample. Images were captured by a Leica DC 300F camera using Kodak Imaging for Windows software connected to the Axioplan microscope (Figure 5.4).

Figure 5.4. Zeiss Axioplan microscope connected to a Leica DC 300F camera and Kodak Imaging software for image capture

5.2.3. Results

Fourteen oil shale samples and one coal sample were prepared as polished sections. The oil shale samples represent material from the lower, middle and upper parts of the Sangkarewang Formation. The coal sample was taken from the Sawahlunto Formation, which stratigraphically overlies the Sangkarewang Formation.

5.2.3.1. Organic Constituents

Microscopic observation indicates that most of the oil shale samples have somewhat similar maceral components. The organic matter in the oil shale samples is

117 dominated by liptinite macerals, particularly alginite (mainly lamalginite) and sporinite. Cutinite and resinite also occur in some samples. Other types of biogenic remains may include shells and fish bones, as fresh water fish fossils are reported to occur in the Sangkarewang Formation (Koesoemadinata and Matasak, 1981; Ilyas, 2001; Suwarna, et al., 2001).

The alginite mostly has a finely banded lamellar structure and is interbedded with mineral matter (Figure 5.5). Some occurs as more irregularly shaped particles, such as can be seen in sample SR 19 (Figure 5.6). The alginite tends to occur as discrete bodies <0.5 mm in size, and as such resembles the material described by Hutton (1987) as “discrete lamalginite”. Alginite is not readily identified in white light (due to its dark colour) but shows bright yellow colours under blue-violet fluorescence illumination.

Fine spheroidal particles with an orange-brown fluorescence are present in some samples, and are discernable in the lower left part of Figure 5.5b. These appear to represent hydrocarbon material (bituminite), probably derived from degradation or early maturation of the lamalginite or other liptinites in the host sediment.

Sporinite may be seen as small particles in some samples (Figure 5.6) Resinite is also present as irregularly shaped bodies, such as can be seen filling cell cavities in sample SR 19 (Figure 5.7). Elongate fluorescent particles tentatively identified as cutinite (Figure 5.8) also occur in some samples (SR 44 and SR 35).

Other biogenic remains were also present in most of the oil shale samples (e.g. SR 24, SR 34, SR 15, SR 19 and SR 37, see Figures 5.9 and 5.10). These were probably derived from fish bones, as previous studies (Koesoemadinata & Matasak, 1981; Ilyas, 2001; Suwarna, et al, 2001) have mentioned the presence of fresh water fish fossils in the Sangkarewang Formation.

The coals from the Sawahlunto Formation are typically vitrinite-rich, with inclusions of liptinite macerals such as sporinite (Figure 5.11).

118 Lam

Bit? (a) (b) Figure 5.5. Lamalginite (Lam) in SR 35 (a) in white light and (b) in fluorescence mode. Fine particles of possible bituminite are also shown.

(a) (b) Figure 5.6. Sporinite (Sp) in SR 19 surrounded by lamalginite (Lam), in white light (a) and in fluorescence mode (b)

Referring to oil shale classification (Hutton, 1987 – see Figure 1.4. in Chapter 1), the dominance of lamalginite in the liptinite components suggests that the material can be describe as lamosite. The organic matter in the Sangkarewang oil shale has similar petrographic features to that in the oil shales from the Rundle area of eastern Australia (Hutton, et al., 1980), and thus would be classified by Hutton (1987) as a Rundle-type lamosite material. As indicated by Hutton (1987), Rundle-type oil shales are derived mainly from green algae and are deposited in fresh to brackish lacustrine conditions. Such an interpretation is consistent with the environment of deposition indicated by the sedimentary features of the sequence in the present study.

119 Res Res

Figure 5.7. Resinite (Res) filling cell cavities of vitrinite (SR 19), viewed in white light (a) and fluorescence mode (b)

Figure 5.8. Elongate particles with orange fluorescence, possibly cutinite (SR 44)

Lam

Fish remains Fish remains

(a) (b) Figure 5.9. Lamalginite (Lam) and fish bones in SR 19: (a) white light, (b) fluorescence mode

120 Fish remains

Fish remains

(a) (b) Figure 5.10. Fish remains in SR 19 viewed in white light (a) and fluorescence mode (b)

Vit Lip

(a) (b) Figure 5.11. Vitrinite (Vit) in coal of the Sawahlunto Formation (SR 28) with liptinite macerals (Lip) in white light (a) and fluorescence mode (b)

5.2.3.2. Vitrinite reflectance

In most of the oil shale samples, the vitrinite reflectance is somewhat difficult to measure due to the small size of the vitrinite particles. Thus, only twenty reflectance measurements were able to be made on each sample. Table 5.1 presents vitrinite reflectance data for the samples from the Sangkarewang oil shale deposit. A coal from the Sawahlunto Formation and a coaly shale from the upper Sangkarewang were also included in the reflectance study.

The samples for reflectance study were collected from different parts of the outcrop area, and not from boreholes or other measured sections. They are listed in

121 stratigraphic order in Table 5.1, with the samples from the lowermost part of the unit at the bottom of the table and those from the overlying Sawahlunto Formation at the top.

Although the depths of the individual samples within the sequence have not been quantified, there appears to be no regular stratigraphic or geographic trend in the vitrinite reflectance values of the Sangkarewang oil shale samples. The vitrinite reflectance values for samples from the lower, middle and upper parts of the Sangkarewang Formation all show somewhat similar values, ranging between 0.37% (SR 14) and 0.55% (SR 35, SR 37). These values are markedly lower than the vitrinite reflectance for the coal in the Sawahlunto Formation (0.68% from sample SR 28), which overlies the Sangkarewang Formation, possibly due to suppression associated with the abundance of liptinite also present. Some samples from the upper part of the Sangkarewang Formation also have fluorescent vitrinite macerals, suggesting the development of more perhydrous characteristics.

Table 5.1. Vitrinite reflectance for samples from the Sangkarewang deposit Sample R Lithology Facies max number (%) SR 28 Coal Sawahlunto Fm 0.63 SR 11 Coaly shale 0.81 SR 24 Shale 0.55 SR 35 Shale 0.55 SR 32 Shale Upper Sangkarewang 0.45 SR 23 Shale 0.45 SR 44 Shale 0.45 SR 34 Shale 0.43 SR 15 Shale 0.45 Middle Sangkarewang SR 17 Shale 0.43 SR 37 Shale 0.55 SR 26 Sandstone 0.47 SR 19 Shale Lower Sangkarewang 0.45 SR 42 Sandstone 0.43 SR 14 Shale 0.37

Hutton and Cook (1980) have noted that the mean maximum vitrinite reflectance of some Australian oil shales is significantly lower in the presence of alginite. Kalkreuth (1982) also found that the vitrinite reflectance in British Colombian coals gradually decreased with increases in liptinite content, and suggested that the effect was caused by

122 diffusion of bituminous substances from the liptinite macerals into the surrounding vitrinite. Gentzis and Goodarzi (1994) and Petersen et al. (2006) have similarly noted suppression of vitrinite reflectance in coals and other sediments, including oil shales, associated with a high proportion of liptinite macerals.

One sample from the upper part of the Sangkarewang Formation, SR 11, by contrast, has a vitrinite reflectance value of 0.81%, higher than that of the other Sangkarewang samples and also higher than that of the overlying Sawahlunto sequence. This sample has abundant vitrinite bands (telocollinite or colotellinite) with high reflectance values, indicating that the sample is closer to a coaly shale than an oil shale sample. Consideration of drilling data from Ilyas (2001) suggests that the horizon repreasnted by this sample may be correlated with thin coal intercalations that occur in the lower part of the Sangkarewang Formation in a borehole log from the Sumpahan Block. Its reflectance is probably less affected by the abundance of liptinites than that of the vitrinite in the other Sangkarewang Formation samples.

The coals in the Sawahlunto Formation have vitrinite reflectance values of 0.6 to 0.8% (Sukardjo, 1989; Herudiyanto, 2004). The coaly shale sample from the Sangkarewang Formation therefore has a reflectance only slightly higher than that found in the overlying Sawhalunto Formation, consistent with its lower position in the sequence and presumably a greater burial depth.

A plot of reflectance value against stratigraphic position was drawn up to show the general trend of reflectance value in the study area (Figure 5.12). This plot indicates that the reflectance values of the Sangkarewang oil shales have values lower than those of the overlying coaly sediments (SR 28 and SR 11). It is generally accepted that sediments lower in the stratigraphic sequence should have higher reflectance than those from higher in the same sequence (Hilt’s Law), due to the greater burial depths involved. The Sangkarewang oil shales, however, show a rather scattered pattern of reflectance values, but those in the lower part of the sequence are clearly lees than those at the top of the stratigraphic succession. In the absence of igneous intrusions in the upper part of the sequence (Koesomadinata & Matasak, 1981; de Smet, 1991), the lower reflectance values probably represent suppression associated with the abundance of

123 liptinite in each of the samples. Sample SR 11, which has high reflectance value, is from material in the Sangkarewang Formation that is dominated by vitrinite, and has less liptinite present to affect the reflectance value. As discussed above, the vitrinite reflectance for SR 11 is also higher than that of SR 28 (a coal sample from the overlying Sawahlunto Formation), possibly indicating the normal trend of the reflectance values expected in the sequence according to Hilt’s Law.

Overall, the Sangkarewang oil shales are dominated by liptinite macerals, and as a result the vitrinite reflectance values in the Sangkarewang oil shales were supressed by the presence of the liptinite components. The sample at the top of the sequence, which has less liptinite material, appears to show a more normal pattern, with values higher than those in the overlying Sawahlunto Formation.

Reflectance (%) 0.0 0.2 0.4 0.6 0.8 1.0

SR 28

SR 11

SR 24

SR 35

SR 32

SR 23

SR 44

SR 34

SR 15

SR 17

SR 37

SR 26

SR 19

SR 42

SR 14

Figure 5.12. Plot showing stratigraphic variation in vitrinite reflectance values given in Table 5.1 (position in sequence not to scale)

124 CHAPTER 6

OIL YIELD AND SPENT SHALE RESIDUES OF THE SANGKAREWANG OIL SHALE DEPOSIT

6.1. Oil Shale Assays

6.1.1. Background

The organic matter in oil shale may be represented by both bitumen and kerogen. Since the bitumen fraction is soluble in most organic solvents, it is not difficult to extract it from oil shale. Bitumen, however, usually makes up only a minor portion of the organic matter (Saxby, 1974). The bulk of the organic matter in oil shales is typically composed of kerogen, which is both inert and insoluble in organic solvents.

The organic matter in oil shale may yield a significant amount of oil upon pyrolysis (see definition of oil shale – Chapter 1). Several factors can affect the oil yield from pyrolysis of oil shale. According to Tissot and Welte (1978), the oil yield depends on the abundance of kerogen in the oil shale, on the nature of the kerogen, and on the natural evolution or thermal maturity of the rock in question.

Tissot and Welte (1978) have reviewed the oil yields from different types of kerogen. Oil shales containing type-I kerogen (telalginite), with a H/C ratio over 1.5, typically show the highest conversion of organic matter into oil. For example, the Green River organic matter of oil shales of Colorado may yield 70% oil, and the organic matter of the kerosene shales of Australia yield 66% oil (Greensmith, 1978). Organic matter in oil shales containing type II kerogen (lamalginite), with a comparatively lower H/C atomic ratio, typically yield 26% oil in Swedish deposits and 66% oil from Russian kukersites (Tissot and Welte, 1978).

125 The oil yield from an oil shale can be assayed by use of the Modified Fischer Retort. This method was introduced by the US Bureau of Mines in 1949. The method represents an improved oil shale assay method relative to the previous method used by the US Bureau of Mines.

The principle of the Modified Fischer Assay procedure is to heat the oil shale sample to 550oC. At this temperature the chemical bonds linking the kerogen macromolecules to the remainder of the rock matrix will be broken, allowing breakdown of the kerogen fraction into small molecules of liquid and gaseous hydrocarbons, nitrogen, sulphur and oxygen compounds (Saxby, 1974).

The design of the Fischer assay retort allows collection of oil and water by condensation, and allows for gas collection in either an inverted graduated cylinder for simple volume measurement or in an evacuated gas receiver for both volume measurement and analysis by gas chromatography.

6.1.2. Analytical Method

Fischer assays were carried out for the present study at the CSIRO Division of Energy Technology at Lucas Heights, NSW. Six oil shale samples were analysed by the Modified Fischer Assay method. These samples represent materials from the upper, middle and lower strata of the Sangkarewang oil shale deposit.

The Modified Fischer Assay apparatus is illustrated in Figure 6.1. Prior to analysis an empty retort (along with its metal plates) and an empty condensate receiver were weighed separately. Approximately 30 grams of each powdered oil shale sample was placed into the weighed retort in layers alternating with metal plates. The metal plates were used for transferring the heat evenly, so that the whole powdered sample could obtain optimum heating at the maximum temperature (550 ºC).

The retort filled with the powdered sample (referred to as “raw shale”) was weighed again to determine the precise mass of the raw shale. The weighed retort and

126 the condensate receiver were then assembled with other supporting equipment (see Figure 6.2) in a fume cupboard. A Eurotherm 812 controller was used to control temperature changes during the retorting process. As temperature increased, oil and water were produced and collected in the condensate receiver.

The heating process was ended at 550 ºC, and the temperature was automatically returned to room temperature. The retort and condensate receiver were removed from the fume cupboard and each of them were again, weighed separately. The increase in mass of the condensate receiver was recorded. This represents the weight of oil and water produced from the retorting process. All measurements were recorded on spreadsheets (example, Table 6.1). The oil was separated from the water by centrifuging. After centrifuging, the water was removed by a pipette, allowing calculation of the weight of oil. The oil yield was calculated in grams / 100 grams of oil shale. Using the average specific gravity of the Sangkarawang oil shales from Ilyas (2000), the oil yield was then converted into litres / tonne of raw shale.

127 Figure 6.1. Modified Fischer Assay retort

128 Figure 6.2. Oil shale retorting unit

Table 6.1. Example of Modified Fischer Assay spreadsheet

Sample name : SR 14 No. Mass retort : 3158.12 g 1 Mass retort + raw shale : 3191.16 g 2 Mass retort + spent shale : 3188.09 g 3 Mass of condensate receiver : 243.24 g 4 Mass of condensate receiver + condensate : 245.73 g 5 Mass of Raw shale : 33.04 g 6 Mass of condensate (oil + water) : 2.49 g 7 Mass of spent shale : 29.97 g Note: no. 5-6 obtained by calculation

Yields Mass (g) Mass (g / 100 g) Oil yield 1.49 4.509 Water yield 1.0 3.027 Spent shale 29.97 90.708 Note: all yields obtained by calculation

129 6.1.3. Results

Six oil shale samples from the Sangkarewang Formation were analysed at the CSIRO laboratory, representing the upper, middle and lower parts of the Sangkarewang deposit. The complete oil assay results are given in Table 6.2. The oil yield per gram of organic carbon (see Chapter 4) in each sample is also indicated.

The samples representing the upper part of the deposit (SR 11 and SR 35) showed significantly higher oil yields compared to the other samples. One sample from the middle part (SR 17) had a markedly low oil yield (1.98 litres/ton). This sample is influenced by material from the Brani breccia, which interfingers with this shale in the Malakutan River exposure (see Chapter 3). The other samples showed moderate oil yields.

The oil density of the Sangkarewang oil shale deposit, as noted by Ilyas (2001), is 0.97 g/cm3. Although the present study shows significantly higher oil yields in the upper part of the sequence (SR 11 and SR 35 in Table 6.2), other studies in different part of the basin (e.g. Hutabarat et al., 1982) suggest that oil yields decrease from the bottom part to the upper part of the Sangkarewang succession.

Table 6.2. Fischer assay data for samples from the Sangkarewang oil shale deposit

Sample Sangkarewang Oil yield Oil yield Oil yield Lithology number facies (g/100 g) (litres/tonne) (g/100 g Corg) SR 11 Coaly shale 11.309 116.59 27.6 Upper SR 35 Shale 6.817 70.28 72.8 SR 17 Shale in breccia Middle 0.192 1.98 16.4 SR 37 Shale 4.057 41.82 57.5 SR 19 Shale Lower 2.414 24.89 59.9 SR 14 Shale 4.509 46.48 96.0

6.1.4. Relation of Oil Yield to Other Shale Properties

Several plots were made to draw correlations between oil yield and the different mineralogical or chemical components (Figures 6.3 to 6.6.). As discussed further by Fatimah and Ward (2008), the oil yield from the samples in the present study is related

130 to the organic carbon content (Figure 6.3). The trend is clear-cut for five of the samples (left-hand side of Figure 6.3), suggesting a simple relation between organic carbon and oil yield. However, the coaly shale sample from the upper Sangkarewang sequence (sample SR-11), with an abundance of vitrinite in the organic matter rather than liptinite (mainly lamalginite, see Chapter 5), shows a different relation between oil yield and organic carbon content to the other samples studied.

Organic Carbon 140

120

100 SR-11

Oil Yield l/t 40

0 0 1020304050 Organic Carbon %

Figure 6.3. Plot of oil yield against organic carbon content, as determined by LECO CNS analyser.

Consideration of the Fischer assay data in relation to the organic carbon content (Table 6.2) indicates that the oil yield represents between 50 and 90% in mass terms of the organic carbon content (50 to 90 g HC/100 g Corg or 500 to 900 mg HC/g Corg).

Some of these are higher than the yields of 50-60% (500 to 600 mg HC/g Corg) indicated for “pure” organic matter in oil shales indicated by authors such as Greensmith (1978) and Taylor et al. (1998). For the coaly shale sample (SR-11), however, the yield represents only around 30% of the organic carbon in the material, probably due to the predominance of vitrinite rather than liptinite in the organic matter (see Chapter 5). Sample SR-17, a limestone with low organic carbon (see Chapter 4), also has a low oil yield per unit mass of organic carbon present.

131 The higher than expected yields of oil per unit mass of organic carbon may possibly be due to incorporation of additional hydrocarbon already generated in the rocks by thermal maturation processes. The vitrinite reflectance of 0.81% in the coaly shale of the upper Sangkarewang Formation (Chapter 5), which is apparently unaffected by suppression effects, is just within the range of 0.8 to 0.9% for calculated Ro values associated with the onset of hydrocarbon generation from Rundle-type lamalginite material (Tegelaar and Noble, 1994). It is therefore possible that, despite the low vitrinite reflectance in the oil shales themselves, the Sangkarewang sequence may have been subjected to burial conditions that would have allowed hydrocarbon generation to commence. The presence of secondary liptinite macerals, such as the traces of bituminite mentioned in Chapter 5, also suggests that some hydrocarbon generation, combined possibly with migration, has taken place in at least some of the samples studied.

Correlations with the XRD data (Chapter 4) show that, with one exception (SR- 17), yield and organic carbon can also be correlated directly with the abundance of carbonate (calcite) and inversely to the abundance of quartz plus feldspar (Figures 6.4 and 6.5).

Calcite 140

120

100

Oil Yield l/t Oil Yield 40

20 SR-17 0 0 10203040506070 Calcite %

Figure 6.4. Plot of oil yield against calcite content, as determined by XRD analysis

132 Quartz + Feldspar 140

120

100

Oil Yield l/t Oil Yield 40

20 SR-17 0 0 10203040 Quartz + Feldspar %

Figure 6.5. Plot of oil yield against quartz plus feldspar, as determined by XRD analysis

No particular correlation seems to be apparent between oil yield or organic carbon content and the overall proportion of clay minerals (Figure 6.6), although a plot of oil yield against calcite plus clay minerals (Figure 6.7), again with the exception of sample SR-17, shows a well-developed positive relationship.

Total Clay Minerals 140

120

t 100

Oil Yield l/ 40

0 0 10203040506070 Total Clay Minerals %

Figure 6.6. Plot of oil yield against total clay minerals, as determined by XRD analysis

133 Calcite + Clay Minerals 140

120

100 t

60 Oil Yield l/ Oil Yield 40

20 SR-17 0 40 50 60 70 80 90 100 Calcite + Clay Minerals %

Figure 6.7. Plot of oil yield against calcite plus clay minerals, as determined by XRD analysis

As discussed by Fatimah and Ward (2008), these correlations suggest a link between the carbonate or carbonate plus clay content of the oil shale samples, the total organic carbon content, and the oil yield. Accumulation and preservation of algal material in the lake sediments that formed the Sangkarewang Formation were probably favoured by deeper-water environments, with low dissolved oxygen and low rates of coarse clastic input (e.g. quartz plus feldspar). Such an environment would have also favoured carbonate deposition, leading to the correlation between oil yield and carbonate content. The correlation between oil yield and clay plus carbonate suggests that fine clays may have also accumulated preferentially in the deep lake environment along with the carbonate and the alginite-forming material.

6.2. Mineralogy of Spent Oil Shale Residues

X-ray diffraction analysis was also carried out on the spent residues of the six oil shale samples. This was intended to observe the behaviour of any expandable-lattice clay minerals. The mineral compositions of spent shale are similar to that of the raw shale making up the respective samples. Figures 6.8 to 6.13 illustrate comparison between diffractograms of raw shale and of the corresponding spent shale.

134 Generally, the clay minerals collapsed upon heating to 550oC, whilst calcite and feldspar minerals remained unchanged. In particular, smectite collapsed and added to the apparent proportion of illite. This can be observed in most of the samples, especially sample SR 14, in which a large proportion of smectite has collapsed to an illite-like structure.

Traces of pyrite and gypsum in the raw shale of sample SR 35 disappeared upon heating to 550oC. The pyrite in this sample may have been transformed to pyrrhotite, as indicated on the diffractogram of the spent residue (Figure 6.9). In some cases, heating could also transform gypsum into anhydrite. Disappearance of the gypsum peak on heating in sample SR 35, however, was not accompanied by the presence of anhydrite peaks in the spent shale diffractogram. This was probably a result of the limited proportion of gypsum in the sample, which made it difficult for any anhydrite to be detected.

Figure 6.8. Comparison between diffractograms of raw shale from SR 11 and the corresponding spent shale

135 Figure 6.9. Comparison between diffractograms of raw shale from SR 35 and the corresponding spent shale

Figure 6.10. Comparison between diffractograms of raw shale from SR 17 and the corresponding spent shale

136 Figure 6.11. Comparison between diffractograms of raw shale from SR 37 and the corresponding spent shale

Figure 6.12. Comparison between diffractograms of raw shale from SR 19 and the corresponding spent shale

137 Figure 6.13 Comparison between diffractograms of raw shale from SR 14 and the corresponding spent shale

138 CHAPTER 7

CONCLUSIONS

Outcrop mapping for this study has shown that the Sangkarewang Formation in the Talawi area can be divided into three facies: the Type A or Sumpahan Facies, the Type B or Santur Facies, and the Type C or Ampang Nago Facies.

The Sumpahan Facies (or Type A lithofacies) forms the lowest part of the Sangkarewang Formation, and is mostly composed of shales with very thin (<0.1 m) laminated sandstones. The shales are light brown to black, with a papery structure, and may show folding or slump structures. The sandstones are light grey, fine grained and carbonaceous, with ripples and parallel bedding and occasional calcite veins. Thin layers of coaly shale also occur in the bottom part of this facies. Mapping shows that the Sumpahan Facies is exposed in the southern part of the study area, around Sawahlunto, particularly in the vicinity of the Sumpahan River.

The Santur Facies (or Type B lithofacies) occurs in the middle part of the Sangkarewang Formation. It is characterised by grey, well-laminated shales with carbonaceous fragments, and in some areas breccia is also present. Sandstone intercalations in this facies are thicker than in the Sumpahan Facies. The thickness of the oil shales in this interval also varies, ranging from 6 m up to 26 m. The Santur Facies is exposed across the central part of the study area, especially near Santur and Kolok villages.

The Ampang Nago Facies (or Type C lithofacies), in the upper part of the Sangkarewang Formation, is dominated by thick layers of sandstone with minor thinly laminated shales. The shales of this lithofacies tend to be more fissile than in the other lithofacies intervals. Turbidite beds up to 1 m in thickness are also common among the sandstones. This lithofacies is exposed in the northern part of the study area, from the Ampang Nago River to the Padang Ganting area.

139

XRD analysis shows that the sediments in the different facies of the Sangkarewang Formation consist mainly of quartz, feldspar, carbonates and a range of clay minerals, together in some cases with minor proportions of sulphide minerals. Some samples are dominated by quartz and feldspar, but others, representing impure lacustrine limestones, are dominated by carbonate minerals.

Comparison of the chemical compositions inferred from quantitative XRD data and the chemical compositions of the same samples by direct analysis shows generally good correlations, including both major element percentages determined by XRF spectrometry and carbonate carbon content determined by LECO element analysis techniques.

Vertical trends in the mineralogy of the shales in the sequence suggest an upward decrease in the abundance of non-kaolinite clay minerals, relative to kaolinite, and also a progressive upward decrease in feldspar abundance. These may be due to changes in the sediment source as the basin was filled. Calcite, which is thought to be mainly of authigenic origin, is also more abundant in the middle and upper parts of the Sangkarewang Formation than in the lower parts of the sequence.

The XRD results suggest that a greater proportion of detrital sediment, rich in feldspar and chlorite and probably derived from relatively unweathered sources, was introduced into the basin in the early stages of Sangkarewang deposition. A sandstone containing abundant chlorite, along with the zeolite mineral laumontite, also present in the lower part of the succession, further suggests derivation from an altered volcanic source material. The chlorite and feldspar appear to have become less abundant as sediment components in the later stages of Sangkarewang deposition, possibly due to changes in provenance or increased weathering in the source area. The increase in carbonate deposition in the upper part of the unit, along with the common presence of pyrite, suggests an increase in authigenic sedimentation in the later stages of deposition (Fatimah and Ward, 2008), consistent with a deeper and more stable lacustrine environment and a more quiescent tectonic setting.

The organic matter in the oil shale samples is dominated by liptinite macerals, particularly alginite (mainly lamalginite) and sporinite. The alginite tends to occur as

140

discrete bodies <0.5 mm in size, and as such resembles the material described by Hutton (1987) as “discrete lamalginite”. Resinite and possibly cutinite also occur in some samples, as well as traces of bituminite. Other types of biogenic remains may include shell fragments and fish bones, consistent with the occurrence of freshwater fish fossils reported by other workers in the Sangkarewang Formation (Koesoemadinata and Matasak, 1981; Ilyas, 2001; Suwarna, et al., 2001).

In accord with similar observations for a Sumatran oil shale by Hutton (1982) and the classification subsequently proposed by Hutton (1987), the dominance of lamalginite in the liptinite components suggests that the material can be described as a lamosite. The organic matter in the Sangkarewang oil shale has similar petrographic features to that in the oil shales from the Rundle area of eastern Australia (Hutton et al., 1980), and thus would be classified by Hutton (1987) as a Rundle-type lamosite material. As indicated by Hutton (1987), Rundle-type oil shales are derived mainly from green algae and are deposited in fresh to brackish lacustrine conditions. Such an interpretation is consistent with the environment of deposition indicated by the sedimentary features of the sequence in the present study.

Although a detailed study of the vertical variation was not possible, the vitrinite reflectance for all of the oil shale samples studied from the Sangkarewang Formation (0.37% to 0.55%) is markedly lower than that of a coaly shale near the top of the sequence (0.81%). It is also lower than the vitrinite reflectance in a coal taken from the overlying Sawahlunto Formation (0.68%). The anomalously low values in the oil shales are thought to be due to reflectance suppression associated with the abundance of liptinite components.

As well as chemical and mineralogical analyses, the work program for this study included Fischer assays of a range of oil shale samples from the Sangkarewang sequence. Together with evaluation of organic carbon content by LECO elemental analyzer, this has shown significant correlations between the proportion of organic carbon in the oil shales and the calcite content, and also between the organic carbon, calcite and calcite + clay percentages and the oil yield. The oil yield from the Fischer assay is also significantly higher, in proportion to organic carbon, for the alginite- bearing oil shales (lamosites) compared to the associated coaly or calcareous shales. 141

This is probably due to differences in the nature of the organic matter (macerals) present.

The correlation between oil yield and carbonate content indicated by this study probably indicates that the organic matter (lamalginite) and the carbonate (calcite) were formed by related processes in the original depositional environment. Accumulation and preservation of algal material in the lake sediments that formed the Sangkarewang Formation preferentially took place in deeper-water lacustrine environments, with low dissolved oxygen and low rates of coarse clastic input (e.g. quartz plus feldspar). Such an environment would have also favoured low clastic input and a dominance of authigenic carbonate deposition, leading to the observed correlation between oil yield and carbonate content.

Particularly high yields of hydrocarbon, as a fraction of the organic carbon content, are indicated for some samples. The higher than expected yields of oil per unit mass of organic carbon in these samples may possibly be due to incorporation of additional hydrocarbon (oil) already generated in the rocks by thermal maturation processes. As discussed further by Fatimah and Ward (2008), the vitrinite reflectance of 0.81% in the coaly shale of the upper Sangkarewang Formation, which is apparently unaffected by suppression effects, is just within the range of 0.8 to 0.9% for calculated Ro values associated with the onset of hydrocarbon generation from Rundle-type lamalginite material (Tegelaar and Noble, 1994). It is therefore possible that, despite the low vitrinite reflectance in the oil shales themselves, the Sangkarewang sequence may have been subjected to burial conditions that would have allowed hydrocarbon generation to have commenced. Identification of bituminite in some of the samples also suggests that hydrocarbon generation, and possibly some migration, may have taken place in at least some parts of the Sangkarewang sequence.

142

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ACKNOWLEDMENTS

Thanks are expressed to the Australian Development Scholarship Program for the financial support to pursue this study, and Prof. Colin R. Ward of the University of New South Wales for his supervision, assistance as well as encouragement to finish this study.

Thanks are also expressed to Dr Hadiyanto and Ir. Asep Suryana of the Department of Energy and Mineral Resources, Indonesia, for developing the project and always supporting the author to finalized this study; as well as Irene Wainwright, Ervin Slansky and Rad Flossman, of the University of New South Wales, and John Levy of CSIRO Energy Technology, for assistance with the laboratory studies, and to Adrian Hutton of the University of Wollongong for advice on the identification of the maceral components.

This study will not accomplish without great support from my beloved husband, Wiwiko Ambardi and understanding from my dear little boys, Athallah Ardifa Ambardi and Azka Wicaksono Ambardi.

May Allah Al Mighty repay all your kindness.

151 APPENDIX 1

Geological map of the Talawi area and its vicinity, West Sumatra Province, Indonesia

APPENDIX 2

Reprint of “Mineralogy and Organic Petrology of Oil Shales in The Sangkarewang Formation, Ombilin Basin, West Sumatra, Indonesia” published in International Journal of Coal Geology, Vol. 77, issues 3- 4, 2008 This article appeared in a journal published by Elsevier. The attached copy is furnished to the author for internal non-commercial research and education use, including for instruction at the authors institution and sharing with colleagues. Other uses, including reproduction and distribution, or selling or licensing copies, or posting to personal, institutional or third party websites are prohibited. In most cases authors are permitted to post their version of the article (e.g. in Word or Tex form) to their personal website or institutional repository. Authors requiring further information regarding Elsevier’s archiving and manuscript policies are encouraged to visit: http://www.elsevier.com/copyright Author's personal copy

International Journal of Coal Geology 77 (2009) 424–435

Contents lists available at ScienceDirect

International Journal of Coal Geology

journal homepage: www.elsevier.com/locate/ijcoalgeo

Mineralogy and organic petrology of oil shales in the Sangkarewang Formation, Ombilin Basin, West Sumatra, Indonesia

Fatimah a,b, Colin R. Ward a,⁎ a School of Biological, Earth and Environmental Sciences, University of New South Wales, Sydney 2052, Australia b Centre for Geological Resources, Department of Mines and Energy, Jalan Soekarno Hatta No. 444, Bandung 40254, Indonesia

ARTICLE INFO ABSTRACT

Article history: The Ombilin Basin is filled by late Eocene to early Oligocene marginal fan deposits (Brani Formation) and Received 12 December 2007 lacustrine shales (Sangkarewang Formation), unconformably overlain by a late Oligocene to early Miocene Received in revised form 23 March 2008 fluvial sequence (Sawahlunto and Sawahtambang Formations) and capped by an early to mid-Miocene Accepted 20 April 2008 marine sequence (Ombilin Formation). Significant oil shale deposits occur in the Sangkarewang Formation, Available online 26 April 2008 intercalated with thin laminated greenish-grey calcareous sandstones. X-ray diffraction shows that the sediments consist mainly of quartz, feldspar, carbonates and a range of clay minerals, together in some cases Keywords: Organic matter with minor proportions of sulphides, evaporites and zeolites. Feldspar and non-kaolinite clay minerals fi Oil shale decrease up the sequence, relative to kaolinite, suggesting a changing sediment source as the basin was lled. Lamosite Calcite, thought to be mainly of authigenic origin, is also more abundant in the middle and upper parts of the Vitrinite reflectance sequence. X-ray diffraction The organic matter in the oil shales of the sequence is dominated by liptinite macerals, particularly alginite Carbonate content (mainly lamalginite) and sporinite. Cutinite also occurs in some samples, along with resinite and traces of Fischer assay bituminite. The dominance of lamalginite in the liptinite components suggests that the material can be described as a lamosite. Samples from the Sangkarewang Formation have vitrinite reflectance values ranging between 0.37% and 0.55%. These are markedly lower than the vitrinite reflectance for coal from the overlying Sawahlunto Formation (0.68%), possibly due to suppression associated with the abundant liptinite in the oil shales. Fischer assay data on outcrop samples indicate that the oil yield is related to the organic carbon content. Correlations with XRD data show that, with one exception, the oil yield and organic carbon can also be correlated directly to the abundance of carbonate (calcite) and inversely to the abundance of quartz plus feldspar. This suggests that the abundance of algal material in the lake sediments was preferentially associated with carbonate deposition. High yields of oil are noted in some samples, as a percentage of the organic carbon content. This may indicate that partial generation of hydrocarbons from the material has already taken place, in association with thermal maturation of the Sangkarewang succession. © 2008 Elsevier B.V. All rights reserved.

1. Introduction (2001), have described geological studies in these areas. Oil shale deposits are also found in other parts of Indonesia, such as Java, Indonesia has a great abundance of oil, gas and coal resources, Sulawesi and Molucca, as well as Papua Island (previously called Irian which have provided the focus for most of the country's energy Jaya). Some of these deposits are spread over large areas but others are exploration to date. Oil shale studies have also been carried out in lenses with a more local distribution (Tobing, 2002; Triono, 2002; Indonesia since the 1980s (e.g. Hutabarat et al., 1982), although often Cahyono, 2003). with scientiﬁc rather than industrial objectives. Many of the deposits, The overall aim of the present study was to extend the understanding nevertheless, still remain little studied and poorly understood. of the Ombilin Basin oil shales by investigating the relationships Some of the main oil shale occurrences in Indonesia are in the between the nature of the basin sediments, the organic matter and the Ombilin Basin and the Central Sumatra Basin (Fig. 1), and several oil yield in the main oil shale bearing succession. This was based on authors, including Hutabarat et al. (1982), Ilyas (2000) and Tobing integrating data from a combination of ﬁeld mapping, mineralogical analysis and organic petrology techniques. It was hoped that any relationships established by the study would provide a more coherent ⁎ Corresponding author. framework for application to other oil shale successions, and a basis for E-mail address: [email protected] (C.R. Ward). better delineating quality trends and improving resource evaluations.

Fatimah, C.R. Ward / International Journal of Coal Geology 77 (2009) 424–435 425

2. Location and geological setting sediments are masked by debris associated with the presently active Marapi volcano (Gunung Marapi). The Ombilin Basin is a Tertiary intermontane basin (de Smet, 1991), Several geological investigations have been carried out in the approximately 25-km wide and 60-km long, trending parallel to the Ombilin Basin, particularly in the western part, where oil shale main axis of the island of Sumatra, Indonesia (Fig. 1). Koning (1985) deposits have been identiﬁed in the Talawi-Sawahlunto area. This describes the Ombilin Basin as a graben-like, pull-apart structure area, which is the focal point of the present study, lies adjacent to the resulting from Early Tertiary tensional tectonics related to strike-slip Trans Sumatra Highway, and can be reached easily from Padang, the movement along the Great Sumatra Fault Zone. capital city of West Sumatra province. The northern part of the basin is divided into eastern and western The Talawi-Sawahlunto area is located in a valley surrounded by segments, separated by prominent basement outcrops on the Bukit mountain ranges. Most of the ranges are covered by tropical rainforest, Tungkar Ridge (Fig. 2). The eastern extension of the basin (the “North but the vegetation in the valleys is dominated by rice crops. The southern Limb” in Fig. 2) continues northward to disappear beneath the part of the area is part of the Tambang Batubara Bukit Asam coal recently extinct Malintang volcano (Gunung Malintang). Another concession, where mining has been taking place since World War II. northern extension of the Ombilin Basin, located southwest of the Bukit Tungkar Ridge, is represented by the Talawi Syncline, a NW–SE 2.1. Stratigraphy trending structure containing a thin section of Tertiary sediments. The Talawi Syncline extends north–westwards from the Sigalut Plateau, The basin is surrounded to the north, east and south, by Permo- near the town of Sawahlunto, to Batusangkar, where the Tertiary Carboniferous slates, phyllites and limestones (parts of the Kuantan

Fig. 1. Location of Ombilin Basin on the island of Sumatra, showing tectonic setting (Koesoemadinata and Matasak, 1981). Author's personal copy

426 Fatimah, C.R. Ward / International Journal of Coal Geology 77 (2009) 424–435

Fig. 2. Geology of the Ombilin Basin in the Sawahlunto-Talawi region (Koesoemadinata and Matasak, 1981), showing the area of focus for the present study. Formation) and large intrusions of granitic rocks. A complex The lower part of the basin ﬁll is represented by late Eocene to assemblage of pre-Tertiary rocks is also exposed along the western early Oligocene marginal fan deposits, referred to by Koesoemadinata margin of the basin, including Permo-Carboniferous and Triassic and Matasak (1981) as the Brani Formation, and lacustrine shales limestones, slates and volcanics and the Middle Cretaceous Lassi referred to as the Sangkarewang Formation (Fig. 3). These are overlain Granite (Koning, 1985). unconformably by a late Oligocene to early Miocene ﬂuvial sequence,

Fig. 3. Stratigraphic column of the Ombilin Basin, showing subdivisions of Koesoemadinata and Matasak (1981) and de Smet (1991). Author's personal copy

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thin sandstones, deposited in a shallow lacustrine setting (Koesoema- dinata and Matasak, 1981). The upper part of the formation is representedmainlybydarkbrown,ﬁssile, calcareous to non-calcareous organic-rich shale deposited in deep anoxic lake conditions. A phase of tectonism, with rapid graben subsidence, initiated the development of deep lake conditions, followed by a long period of quiescence and organic-rich shale accumulation.

2.1.3. Sawahlunto Formation The Sawahlunto Formation consists of shale, siltstone, quartz sandstone and coal, and occurs mostly in the northeastern part of the basin. The sandstones are locally coarse to very coarse, and occur mainly as channel ﬁlls formed by migrating point bars. The coals in this formation are mined at Sawahlunto. Based on the presence of carbonaceous shales, coals and especially point bar sandstones, the Sawahlunto Formation is thought to represent ﬂood basin and meandering river deposits (Koesoemadinata and Matasak, 1981). The clastic particles in the Sawahlunto sediments have better rounding than those in the Brani or Sangkarewang units, and have clearly been more extensively transported before deposition. The sediments contain no macro-fossils, but have an abundant pollen content (Koesoemadinata and Matasak, 1981).

2.1.4. Ombilin Formation The Ombilin Formation is characterised by dark grey shales, which are often calcareous. In the centre of basin the unit locally contains limestone lenses, with coral debris, shell and plant remains. The shales have intercalations of siltstone and glauconitic sandstone. The Ombilin Formation is distributed with a north–south trend in the Fig. 4. Outcrops of Sangkarewang Formation in the Sumpahan River area: (A) SR-35 and eastern part of the Talawi Syncline. (B) SR-32, showing thin bedding of shaly strata. (For interpretation of the references to Some Quaternary volcanic deposits, represented mainly by pumice colour in this figure legend, the reader is referred to the web version of this article.) in a glass shard matrix, also occur in the central and northern parts of the syncline area. the Sawahlunto and Sawahtambang Formations, and capped by an 2.2. Lithofacies of the Sangkarewang Formation early to mid-Miocene marine sequence, the Ombilin Formation. Significant oil shale deposits occur in the Sangkarewang Forma- 2.1.1. Brani Formation tion, intercalated with the turbidite sandstones. Field observation The Brani Formation is a sequence of breccias and polymictic indicates that there are three sedimentary facies associated with the pebble to cobble conglomerates with a muddy to sandy matrix, Sangkarewang oil shale deposits: formed partly as alluvial fan and partly as coastal deposits. The unit is The Sumpahan Facies (or type A lithofacies) occurs in the lowest interbedded with and partly time-equivalent to the sediments of the part of the Sangkarewang Formation, and is mostly composed of Sangkarewang Formation; in some locations clasts of shale apparently shales (up to 95%), with very thin laminated sandstones (less than derived as soft sediment from the Sangkarewang occur within the 0.10 m in thickness). The shales are light brown to black, with very breccias of the Brani Formation. Koesoemadinata and Matasak (1981) thin blades (papery structure). In some places the shale laminae are indicate that the Brani breccia typically has a purple-brown colour, folded and show slump structures. The sandstone layers are light grey which de Smet (1991) suggests is related to a network of centimetre- in colour, fine grained and carbonaceous, with ripples and parallel thick veins that indicate the former presence of rootlets. bedding and occasional calcite veins. Thin layers of coaly shale (approximately 200 mm in thickness) also occur in the bottom part of 2.1.2. Sangkarewang Formation this facies. The facies is exposed in the southern part of the study area, The Sangkarewang Formation consists of dark bluish grey to black around Sawahlunto, particularly in the vicinity of the Sumpahan laminated shales, including oil shales (Fig. 4). The shales are typically River. plastic and papery and are locally calcareous, and fall apart easily The Santur Facies (or type B lithofacies) occurs in the middle part of along the laminae when dry and form thin blades or papery sheets. the Sangkarewang Formation, and is characterised by grey, well- Intercalation of greenish-grey feldspathic turbidite sandstones is laminated shales with carbonaceous fragments. Some breccia is also common, typically showing fining upward sequences and containing present. Sandstone intercalations in this facies are thicker than in the mica and carbonaceous material. The turbidite beds show thicknesses Sumpahan Facies. The thickness of the oil shales in this interval also of up to 1 m, and locally have complete Bouma sets. Slump structures varies, ranging from 6 m up to 26 m. The Santur Facies is exposed are also prevalent, and plant remains are often preserved on the across the central part of the study area, especially near the Santur and lamination planes. The percentage and thickness of the turbidites, as Kolok villages. well as the abundance of slump-related features, tend to increase The Ampang Nago Facies (or type C lithofacies) is dominated by upwards in the stratigraphic section. thick layers of sandstone with minor thinly laminated shales. The The Sangkarewang Formation was deposited in a stable lacustrine shale of this lithofacies tends to be more fissile than in the other environment with euxinic conditions, possibly in a large lake covering at lithofacies types. Turbidite beds up to 1 m in thickness are also least 1000 km2. The lower part of the formation consists dominantly of common among the sandstones. This lithofacies, which is the dark silty shales with minor variously coloured shales and interbedded youngest in the Sangkarewang section, is exposed in the northern Author's personal copy

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Table 1

Mineralogy (wt.%) and vitrinite reﬂectance (Rvmax %) of samples used in the study

Sample Location Lithology Facies Qtz Albite Orth Illite Kaol Smec I/S Chl Pyrite Calcite Ank Sid Gyp Laum Rvmax SR 28 Sawahlunto Coal Sawahlunto Fm 0.63 SR 11 Sumpahan River Coaly shale Ampang Nago 0.1 70.1 29.8 0.81 SR 3 Sumpahan River Shale Ampang Nago 12.0 0.7 9.2 15.3 6.8 3.4 52.6 SR 35 Sumpahan River Shale Ampang Nago 15.0 1.1 0.4 4.2 30.8 1.4 6.6 3.3 34.7 2.5 0.55 SR 32 Sumpahan Rive Shale Ampang Nago 21.1 2.5 0.2 15.0 30.4 1.3 6.5 1.4 2.1 9.8 4.5 5.2 0.45 SR 15 Malakutan River Shale Santur 17.8 8.9 2.0 5.9 30.2 4.4 15.0 15.8 0.45 SR 17 Malakutan River Shale in breccia Santur 17.2 12.8 0.7 2.5 3.0 0.4 1.5 61.8 0.43 SR 21 Kolok Sandstone Santur 41.3 5.2 13.7 17.1 7.1 3.7 1.8 10.1 SR 25 Kolok Sandstone Santur 18.0 8.8 1.0 1.9 5.5 0.8 3.2 60.7 SR 5 Talawi Shale Sumpahan 14.6 15.3 6.4 15.9 21.9 9.0 5.0 11.8 SR 8 Talawi Sandstone Sumpahan 12.3 17.7 3.1 19.2 17.0 10.3 14.9 5.5 SR 14 Sipang River Shale Sumpahan 16.8 11.5 0.8 17.6 25.6 1.8 10.9 7.7 7.4 0.37 SR 7 Sipang River Shale Sumpahan 15.9 10.1 1.5 12.3 25.5 14.9 19.1 0.4 0.3 SR 19 Sipang River Shale Sumpahan 25.7 11.4 2.0 9.8 20.5 2.5 6.8 5.9 15.5 0.45 SR 6 Sipang River Shale Sumpahan 30.5 11.4 2.9 6.0 31.4 7.0 3.6 7.2 SR 26 Sipang River Sandstone Sumpahan 27.0 22.6 4.5 10.0 16.4 10.2 2.4 7.0 0.47 SR 42 Ampang Nago Sandstone Sumpahan 18.4 23.7 4.6 16.7 17.9 3.7 8.3 6.7 SR 37 Ampang Nago Shale Sumpahan 14.9 10.7 22.9 25.3 2.3 3.4 0.1 20.4 0.55 SR 43 Padang Ganting Sandstone Sumpahan 23.4 11.9 3.4 5.0 16.5 5.2 24.9 0.4 9.4

Qtz = quartz; Orth = orthoclase; Kaol = kaolinite; Smec = smectite; I/S = interstratiﬁed illite/smectite; Chl = chlorite; Ank = ankerite; Sid = siderite; Gyp = gypsum; Laum = laumontite.

part of the study area, from the Ampang Nago River to the Padang overlying Sawahlunto Formation was also included, for comparison, in Ganting area. the sample suite. The samples were taken where possible from exposures in flowing 3. Materials and methods river beds, to provide fresh material for the analysis program. This was especially significant for evaluation of those aspects concerned Samples of the oil shale and associated lithologies in the with the organic matter. Although the lithofacies interval from which Sangkarewang Formation were taken from exposures in the Talawi each sample was taken could be identified, the distribution of the area (Table 1) for analysis by a number of different techniques. Among sampling sites with respect to the structure and topography of the other factors, this was intended to evaluate the features that influence area prevented a more detailed assessment of the stratigraphic the yield of oil from different types of materials, and provide a better relationships among the individual samples within those lithofacies framework for future economic assessments. A coal sample from the units. No stratigraphic succession is therefore implied, beyond the

Fig. 5. Typical XRD patterns of samples from the Sangkarewang Formation: Sample SR-3 (bottom), SR-26 (middle) and SR-7 (top). Author's personal copy

Fatimah, C.R. Ward / International Journal of Coal Geology 77 (2009) 424–435 429 major subdivisions, by the order in which the samples are listed in Mean maximum vitrinite reflectance in oil (n oil=1.518 at 23 °C) Table 1. was measured using a Zeiss MSP21 Microscope System Processor, with The mineralogy, texture, and chemical and petrographic composi- calibration against a glass standard with a reflectance of 0.51%. Twenty tion of the samples were investigated using quantitative X-ray reflectance measurements were made on each sample. Images in diffraction, X-ray fluorescence spectrometry, elemental analysis (to white and blue-violet light were captured using a Leica DC 300F determine organic and carbonate carbon content), optical microscopy camera attached to the Axioplan microscope. and Fischer assay techniques. Mean maximum reflectance of vitrinite Observation of thin sections for selected rock types was carried out in a number of samples was also measured, including that in the coal in transmitted light using a Zeiss Axioskop polarizing microscope, from the Sawahlunto Formation. with objective lenses having ×20 and ×40 magnification. Images were captured using an ISSCO-CCD colour camera and Snappy 2.1 software, 3.1. X-ray diffraction connected to a Leitz HM-Pol microscope unit.

Representative portions of 18 samples were ground to less than 3.5. Fischer assay about 200 mesh (b63 μm), and the powders subjected to X-ray diffractometry (XRD) using a Philips PW1830 diffractometer system Six oil shale samples were analysed by the Modified Fischer Assay using Cu-Kα radiation. Scans were run from 2° to 60° 2θ, with 0.04° method, using facilities at the CSIRO Division of Energy Technology. step interval and a two second step count. Typical X-ray diffraction Approximately 30 g of each shale sample was heated in an aluminium patterns are illustrated in Fig. 5. retort to 550 °C at 12 °C/min, and held at that temperature for 40 min. The clay (b2 μm) fraction for each sample was also concentrated by The increase in mass of the condensate receiver was recorded, and the settling in water, and oriented-aggregate mounts prepared using the oil separated from the water by centrifuging. The oil yield was pipette-on-glass-slide technique (Gibbs, 1971). Each mount was calculated in grams per 100 g of oil shale, and converted to litres per further analysed by XRD after exposure to ethylene glycol and after tonne of raw shale using density data for Sangkarawang oil shales heatingto400°C,toprovidemorespecificidentification the from Ilyas (2000). expandable-lattice clay minerals (Griffin, 1971; Hardy and Tucker, 1988; Moore and Reynolds, 1997). 4. Results and discussion Quantitative analysis of the mineral proportions in each powdered rock sample was carried out using the Siroquant™ XRD processing 4.1. Mineralogy system (Taylor, 1991), based on the principles developed by Rietveld (1969). Application of this software to similar materials is discussed XRD analysis (Table 1) shows that the Sangkarewang Formation further by Ward et al. (1999, 2001), Ruan and Ward (2002) and Ward sediments consist mainly of quartz, feldspar, carbonates and a range of and Gomez-Fernandez (2003). clay minerals, together in some cases with minor proportions of sulphide minerals. Some samples are dominated by quartz and 3.2. X-ray fluorescence spectrometry feldspar, but others, representing impure lacustrine limestones, are dominated by carbonate minerals. Other representative portions of 21 powdered rock samples were The proportion of quartz in the sediments, especially the shaly calcined at 1050 °C, and the loss-on-ignition determined. The calcined materials, is relatively consistent (10–30%) throughout the succession. shale was then fused with lithium tetraborate and cast into a mould, Feldspar, identified mainly as albite but including some orthoclase, is following the procedure of Norrish and Chappell (1977). The discs relatively abundant (10–25%) in the lower part (Sumpahan and Santur were analysed using a Philips PW 2400 X-ray fluorescence (XRF) Facies) of the Sangkarewang Formation, but only a rare component spectrometer system, with SuperQ software for the major element (b3%) of the shales in the upper part of the sequence (Ampang Nago determinations. Facies). With the exception of some very carbonate-rich samples (e.g. SR- 3.3. Carbon determinations 17 and SR-25), kaolinite typically makes up between 15 and 30% of the samples studied. Illite, smectite, interstratified illite–smectite and The total carbon content for 16 of the samples was determined chlorite are abundant in the samples from the lower and middle parts using a LECO CNS-2000 elemental analyser. This included both the of the sequence, but less abundant, relative to kaolinite, in the upper organic carbon and inorganic (carbonate) carbon contents. part of the succession. The coaly shale in the upper part of the The organic carbon content of each sample was determined by Sangkarewang Formation (Sample SR-11) is unusual, relative to the similar analysis of separate splits of the samples that had been treated other samples, in that it has a mineral fraction consisting almost with hydrochloric acid to remove the carbonate component. The acid- entirely of carbonate components. treated samples were washed, dried in an oven, and analysed by the Except for SR-11, which also contains ankerite, and SR-32, which LECO CNS-2000 to determine the organic carbon content of each rock contains a small proportion of siderite, calcite is the only carbonate sample. The proportion of carbon in carbonate form, represented by mineral identified in the samples by the XRD study. High proportions the material dissolved by the acid treatment, was then determined of calcite (up to 50%) commonly occur in shales from the middle and from the difference between the organic carbon and the total carbon upper parts of the Sangkarewang Formation (Ampang Nago and contents. Santur Facies), whereas samples from the lower part (Sumpahan Facies) tend to have somewhat lower calcite contents (mostly less 3.4. Optical microscopy than 10%). Pyrite, where present, also tends to be more common in the shales from the middle and upper parts of the sequence. Fifteen rock samples from the study area were prepared as The mineralogical data suggest that a greater proportion of detrital polished sections for maceral analysis and vitrinite reflectance sediment, rich in feldspar and chlorite and probably derived from measurement. Examination was carried out using a Zeiss Axioplan relatively unweathered sources, was introduced into the basin in the microscope with an Epiplan ‘Neo fluar’ ×50 objective under oil early stages of Sangkarewang deposition. A sandstone containing immersion. Vitrinite and inertinite groups were identified using abundant chlorite, along with the zeolite mineral laumontite, is also white light; the liptinite group macerals were identified using blue- present in the lower part of the succession, suggesting derivation from violet light to observe their fluorescence properties. an altered volcanic source material. The chlorite and feldspar appear Author's personal copy

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Table 2 Chemical analysis of samples by XRF analysis (wt.%)

Sample SiO2 Al2O3 TiO2 Fe2O3 MnO CaO MgO K2ONa2OP2O5 SO3 LOI Total SR 11 1.83 0.43 0.05 3.23 0.074 20.41 2.49 0.27 0.25 0.045 1.262 71.50 101.84 SR 3 23.54 8.78 0.24 5.09 0.093 26.16 0.92 0.98 0.38 0.262 2.647 33.24 102.33 SR 35 26.13 11.62 0.34 4.72 0.055 22.83 1.02 0.86 0.21 0.115 3.432 31.69 103.02 SR 32 43.81 17.79 0.59 7.28 0.274 7.11 1.48 1.82 0.31 0.184 2.134 17.88 100.66 SR 15 46.92 14.91 0.51 7.41 0.132 9.27 1.71 1.37 1.34 0.157 1.365 18.56 103.65 SR 17 43.74 3.60 0.22 1.94 0.291 25.54 0.76 0.70 0.83 0.246 0.521 21.20 99.58 SR 21 64.35 11.84 0.56 2.59 0.635 6.67 1.22 1.21 0.84 0.086 1.403 9.11 100.52 SR 25 32.68 7.32 0.30 2.96 0.290 28.47 1.20 1.03 1.13 0.082 0.757 24.50 100.72 SR 5 51.19 15.30 0.61 6.35 0.086 7.34 2.00 2.29 1.69 0.186 0.523 13.17 100.74 SR 8 59.85 15.21 0.55 7.09 0.063 3.29 2.06 2.48 2.55 0.134 0.15 6.07 99.49 SR 14 49.69 18.07 0.71 4.32 0.037 5.45 1.66 2.19 1.33 0.176 0.643 16.03 100.31 SR 7 49.80 22.39 1.01 6.18 0.048 0.96 1.81 2.27 0.84 0.129 0.199 13.90 99.54 SR 19 46.16 15.22 0.59 5.05 0.067 9.93 1.33 1.77 0.93 0.112 0.579 18.09 99.83 SR 6 52.67 19.41 0.75 3.66 0.030 4.80 1.24 1.95 0.95 0.081 0.279 13.98 99.79 SR 26 63.52 14.41 0.49 3.37 0.058 4.32 1.18 2.09 2.47 0.156 0.808 7.11 99.99 SR 42 60.51 14.14 0.44 6.41 0.089 4.10 1.82 2.64 2.40 0.124 0.116 6.23 99.02 SR 37 40.84 16.48 0.70 5.64 0.087 8.50 1.93 2.12 1.07 0.155 0.253 23.17 100.95 SR 43 63.19 15.27 0.69 6.74 0.094 1.73 2.09 1.92 2.85 0.122 0.044 4.56 99.29

to have become less abundant as sediment components in the later The plot for CaO (derived mainly from the calcite in the samples) stages of the unit's history, possibly due to changes in provenance or shows a relatively good correlation (R2 =0.84), with all but one point increased weathering in the source area. The increase in carbonate falling close to the equality line. The outlier point (SR-11) represents deposition in the upper part of the unit, along with the common the coaly shale from the sample suite. This sample has around 40% presence of pyrite, suggests an increase in authigenic sedimentation in organic carbon (see below), compared to the other samples which the later stages of deposition, consistent with a deeper and more have less than 10% and often less than 5% organic carbon. The XRD stable lacustrine environment and a more quiescent tectonic setting. data do not include the organic matter content of the samples. In most cases this makes only a very minor difference to the comparison, but 4.2. Chemical composition for this sample dilution by the abundant organic matter would significantly reduce the otherwise high CaO content, making the The proportions of major elements in the samples analysed by XRF, inferred proportion of CaO close to that measured by XRF analysis of expressed as the relevant oxides, are given in Table 2. These were the material including the organic matter. compared to the inferred chemical composition for each sample The plot for MgO shows an overall poor correlation (R2 =0.58), with derived from the mineral percentages determined by the Siroquant a broad grouping of data points clustered mainly below the equality evaluations, following principles discussed further by Ward et al. line. This partly reflects the low percentages of Mg-bearing minerals in (1999). relation to the errors associated with the Siroquant measurements. A Comparison of the proportions of each major element oxide small proportion of Mg may be also included in the calcite found in the inferred from the XRD data to the actual percentage of each oxide rock samples, but this was not allowed for in calculating the inferred determined by the XRF analysis shows relatively good correlations in chemical compositions from the XRD data. As discussed above, if most cases (Fig. 6). As with similar evaluations for other types of allowance is made for dilution by the abundant organic matter, the material (Ward et al., 1999, 2001; Ruan and Ward, 2002; Ward and outlier represented by SR-11 would also plot relatively close to the Gomez-Fernandez, 2003), the relationship identified in each plot is equality line. expressed by the linear regression equation in the form: y=ax+b, The inferred proportions of CO2 and H2O, derived from the where a is the slope of the regression line, and b is the intercept on the percentages of the carbonate and clay minerals, combined with the y axis. The coefficient correlation (R2) is also shown in each case, percentage of organic carbon determined by independent element together with a diagonal line corresponding to the location of the analysis (see below), show a good correlation with the loss-on- points for a perfect correlation between the respective data points. A ignition (LOI) for the individual samples determined as part of the XRF perfect correlation in each case would show a=1, b=0 and R2 =1.00 analysis process. Most points plot close to the equality line. Only the from this regression analysis. coaly shale sample (SR-11) shows a significant difference, possibly due

The points for SiO2,K2O and Na2O lie close to the equality line in to cumulative errors in assessing the high proportions of the different their respective plots, with regression equations close to the ideal of components involved. a=1 and b=0 and with high correlation coefficients (R2 N0.68). The Bearing in mind the difficulties associated with sample SR-11, and points for Al2O3 lie above the equality line, indicating a higher the possibility that some of the clay minerals may be more iron-rich proportion inferred from the Siroquant data than was directly than allowed for in the calculations, quantitative mineralogical determined by chemical analysis. However, as discussed by Ward et analysis by XRD and Siroquant appears to provide data that are al. (1999), the illite, illite–smectite and chlorite compositions used to consistent with the independently measured chemical composition of calculate the inferred chemistry assumed no more than minimal the same rock samples, and hence confirm the quantifications incorporation of Fe into the lattice structure. If the composition of associated with the XRD analysis process. these clay minerals in the samples is more iron-rich, with some Al or Mg in the respective lattices replaced by Fe, and if there are no other 4.3. Carbonate and organic carbon Fe-bearing minerals in the samples studied (only a small proportion of siderite or pyrite occurs in some samples), then the bulk of the Fe must Correlations between the proportion of carbonate carbon in the also be present in the non-kaolinite clay minerals. To confirm this, samples determined by elemental analysis (Table 3)andthe

Al2O3 and Fe2O3 were considered together in the one plot, which proportion of calcite indicated by XRD (Table 1) are indicated in showed a very good correlation (a=1.02, b=0.35, R2 =0.89). Fig. 7. The coaly shale sample (SR-11) was not included in this plot, due Author's personal copy

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Fig. 6. Plots showing correlations between percentages of major element oxides inferred from XRD data to percentages of the equivalent oxides determined by XRF analysis. Author's personal copy

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Table 3 as discrete bodies b0.5 mm in size, and as such resembles the material Total, organic and carbonate carbon percentages in samples studied described by Hutton (1987) as “discrete lamalginite”. Cutinite and Sample number Lithology Total carbon Organic carbon Carbonate carbon resinite also occur in some samples. Other types of biogenic remains fi fi SR 11 Coaly shale 43.92 40.94 2.98 may include shells and sh bones, as fresh water sh fossils are SR 3 Shale 11.98 6.75 5.24 reported to occur in the Sangkarewang Formation (Koesoemadinata SR 35 Shale 12.81 9.36 3.45 and Matasak, 1981; Ilyas, 2001; Suwarna et al., 2001). SR 32 Shale 5.49 3.80 1.69 In accord with similar observations for a Sumatran oil shale by SR 15 Shale 5.21 3.40 1.81 fi SR 17 Shale in breccia 8.54 1.17 7.37 Hutton (1982) and the classi cation subsequently proposed by Hutton SR 37 Shale 9.40 7.05 2.35 (1987), the dominance of lamalginite in the liptinite components SR 5 Shale 3.86 2.43 1.43 suggests that the material can be described as a lamosite. The organic SR 8 Sandstone 6.08 4.21 1.87 matter in the Sangkarewang oil shale has similar petrographic SR 19 Shale 6.01 4.03 1.98 features to that in the oil shales from the Rundle area of eastern SR 42 Sandstone 9.07 6.86 2.23 fi SR 14 Shale 5.70 4.70 1.00 Australia (Hutton et al., 1980), and thus would be classi ed by Hutton SR 6 Shale 3.13 2.41 0.72 (1987) as a Rundle-type lamosite material. As indicated by Hutton (1987), Rundle-type oil shales are derived mainly from green algae and are deposited in fresh to brackish lacustrine conditions. Such an to difficulties in allowing for its high organic carbon content. The data interpretation is consistent with the environment of deposition points show a high correlation coefficient (R2 =0.95), and plot close to indicated by the sedimentary features of the sequence in the present the line representing the values in each case expected from chemical study. stoichiometry. This suggests again that the XRD quantifications for the The vitrinite reflectance values for samples from the lower, middle oil shale samples are consistent with independent chemical data. and upper parts of the Sangkarewang Formation all show somewhat A more scattered but nevertheless discernable correlation similar values, ranging between 0.37% and 0.55% (Table 1). These (R2 =0.53) is noted in Fig. 7 between the organic carbon content of values are markedly lower than the vitrinite reflectance for a coal from the oil shales and the calcite content. The coaly shale sample (SR-11), the overlying Sawahlunto Formation (0.68%, Table 1), possibly due to with 40% organic carbon (Table 3) was not included in this plot, partly suppression associated with the abundance of liptinite in the oil because it represents a different lithology to the other shale samples. shales. Some samples from the upper part of the Sangkarewang Sample SR-17, which was taken from a calcareous shale fragment Formation also have fluorescent vitrinite macerals, suggesting the contained within a breccia unit of the Sangkarewang sequence or an development of more perhydrous characteristics. interfingering horizon of the Brani Formation, was also not included in Hutton and Cook (1980) noted that the mean maximum vitrinite the correlation. This sample has a much lower organic carbon content reflectance of some Australian oil shales is significantly lower in the than the oil shales otherwise represented in the sequence, and again presence of alginite. Kalkreuth (1982) also found that the vitrinite appears to represent a different rock type. reflectance in British Colombian coals gradually decreased with increases in liptinite content, and suggested that the effect was 4.4. Organic petrology caused by diffusion of bituminous substances from the liptinite macerals into the surrounding vitrinite. Gentzis and Goodarzi (1994) Thin sections of samples, especially those from the lower part of and Petersen et al. (2006) have similarly noted suppression of vitrinite the Sangkarewang Formation, show layers alternating between silt reflectance in coals and other sediments, including oil shales, and fine sand size. Quartz, plagioclase feldspar, biotite mica and associated with a high proportion of liptinite macerals. chlorite are the main components visible under the microscope, with One sample from the upper part of the Sangkarewang Formation calcite also abundant in the silty layers. Mica is included with illite and (SR-11) has a vitrinite reflectance value of 0.81%, higher than that of plagioclase feldspar is identified as albite in the XRD data of Table 1. the other Sangkarewang samples and also higher than that found in The abundance of plagioclase and biotite indicate that the sediments the overlying Sawahlunto sequence. This sample has abundant were derived mainly from igneous (possibly granitic) sources, and vitrinite (collotelinite) bands and represents a coaly shale rather were transported over only relatively short distances (i.e. the than an oil shale; it may thus represent the thermal history of the sediment is close to its original provenance area). Sangkarewang sequence more clearly than samples in which the Polished section studies (Fig. 8) show that the organic matter in the reflectance is anomalously low due to abundant liptinite. The coals in oil shale samples is dominated by liptinite macerals, particularly the Sawahlunto Formation have vitrinite reflectance values of 0.6 to alginite (mainly lamalginite) and sporinite. The alginite tends to occur 0.8% (Sukardjo, 1989; Herudiyanto, 2004). The coaly shale sample

Fig. 7. Correlations between carbonate carbon and calcite as determined by XRD (left), and organic carbon and calcite content (right). Coaly shale sample SR-11 excluded. Author's personal copy

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Fig. 8. Polished sections of Sangkarewang oil shales showing mode of occurrence of liptinite macerals: (A) Lamalginite in sample SR-19, (B) Lamalginite in sample SR-35, (C and D) Resinite in cell cavities of vitinite, Sample SR-19. All except (C) blue-violet illumination. Field width (all sections) 1 mm. (For interpretation of the references to colour in this ﬁgure legend, the reader is referred to the web version of this article.)

from the Sangkarewang Formation therefore has a reflectance only Taylor et al. (1998). For the coaly shale sample (SR-11), however, the slightly higher than that found in the overlying Sawhalunto Forma- yield represents only around 30% of the organic carbon in the material, tion, consistent with its lower position in the sequence and probably due to the predominance of vitrinite rather than liptinite in presumably a greater burial depth. the organic matter. Sample SR-17, a limestone with low organic Fine spheroidal particles with an orange-brown fluorescence are carbon, also has a low oil yield per unit mass of organic carbon present in some samples, and are discernable in the lower left part of present. Fig. 8B. These appear to represent hydrocarbon material (bituminite), The higher than expected yields of oil per unit mass of organic probably derived from degradation or early maturation of the carbon may possibly be due to incorporation of additional hydro- lamalginite or other liptinites in the host sediment. carbon already generated in the rocks by thermal maturation processes. The vitrinite reflectance of 0.81% in the coaly shale of the 4.5. Oil yield and shale mineralogy upper Sangkarewang Formation, which is apparently unaffected by suppression effects, is just within the range of 0.8 to 0.9% for Fischer assay data on outcrop samples from the upper, middle and calculated Ro values associated with the onset of hydrocarbon lower parts of the Sangkarewang Formation (Table 4) show signifi- generation from Rundle-type lamalginite material (Tegelaar and cantly higher oil yields in the upper part of the sequence (SR-11 and Noble, 1994). It is therefore possible that, despite the low vitrinite SR-35) compared to the other samples studied. Other studies in reflectance in the oil shales themselves, the Sangkarewang sequence different parts of the basin (e.g. Hutabarat et al., 1982), however, may have been subjected to burial conditions that would have allowed suggest that oil yields decrease from the bottom part to the upper part of the Sangkarewang succession. The oil yield from the samples in the present study is related to the Table 4 organic carbon content (Fig. 9). The coaly shale sample in Table 4, Fischer assay data for samples from the Sangkarewang Formation however (sample SR-11), with an abundance of vitrinite in the organic matter rather than liptinite, shows a slightly different relation between Sample Lithology Sangkarewang Oil yield Oil yield Oil yield oil yield and organic carbon content than the other samples studied. number facies (g/100 g) (litres/tonne) (mg/g Corg) Consideration of the Fischer assay data in relation to the organic SR 11 Coaly shale Ampang Nago 11.309 116.59 27.6 SR 35 Shale 6.817 70.28 72.8 carbon content (Fig. 9A) indicates that the oil yield represents SR 17 Shale in Santur 0.192 1.98 16.4 between 50 and 90% in mass terms of the organic carbon content breccia (500 to 900 mg HC/g Corg; Table 4). Some of these are higher than the SR 37 Shale Sumpahan 4.057 41.82 57.5 SR 19 Shale 2.414 24.89 59.9 yields of 50–60% (500 to 600 mg HC/g Corg) indicated for “pure” SR 14 Shale 4.509 46.48 96.0 organic matter in oil shales by authors such as Greensmith (1978) and Author's personal copy

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Fig. 9. Relation of oil yield to (A) organic carbon, (B) carbonate (calcite) content, (C) quartz+feldspar content and (D) total clay mineral content for samples tested by Fischer assay.

hydrocarbon generation to commence. The presence of secondary The organic matter in the oil shales of the Sangkarewang sequence liptinite macerals, such as the bituminite mentioned above, also is mainly represented by lamalginite, with minor proportions of suggests that some hydrocarbon generation, combined possibly with sporinite, cutinite and other liptinite components. Based on compar- migration, has taken place in at least some of the samples studied. isons to the work of Hutton (1982, 1987), the shales are classified as Correlations with the XRD data show that, with one exception (SR- lamosites. As with several other such successions, the vitrinite 17), yield and organic carbon can also be correlated directly with the reflectance in the oil shales is anomalously low, relative to coals and abundance of carbonate (calcite) and inversely to the abundance of coaly shales higher in the sequence, due to an intimate association of quartz plus feldspar (Fig. 9B–C). Accumulation and preservation of the vitrinite with the abundant liptinite macerals. algal material in the lake sediments were probably favoured by a deep- Correlations have been identified between the proportion of water environment, with low dissolved oxygen and low rates of clastic organic carbon in the oil shales and the calcite content, and between input. Such an environment would have also favoured carbonate organic carbon, calcite and oil yield. Other rocks in the sequence, such deposition, leading to the correlations mentioned above. No particular as coaly shale or calcareous shale occurring as clasts in breccia, display correlation seems to be apparent between oil yield or organic carbon different relationships between their carbonate and organic carbon content and the overall proportion of clay minerals (Fig. 9D). Together contents. The oil yield, determined by a modified Fischer assay with the inverse correlation with quartz plus feldspar mentioned technique, is significantly higher in proportion to organic carbon for above, this suggests that fine clays, but not coarser-grained quartz and the lamosites, compared to the associated coaly or calcareous shales, feldspar particles, may have also accumulated in the deep lake due to differences in the nature of the macerals present. Particularly environment along with the carbonate and the algal material. high yields of hydrocarbon as a fraction of the organic carbon content, indicated for some samples, may reflect the presence of oil already 5. Conclusions generated within the Sangkarewang succession.

The oil shales of the Sangkarewang Formation were deposited in a Acknowledgements relatively deep lacustrine environment, interbedded with turbidite deposits. The mineralogy of the sediments, evaluated by quantitative Thanks are expressed to the Australian Development Scholarship X-ray diffraction, shows a good correlation with independent Program for the financial support to pursue this study, and to Dr chemical data, including both major element percentages determined Hadiyanto, of the Department of Mines and Energy, Indonesia, for by XRF spectrometry and carbonate carbon content determined by developing the project and providing support for the field work. element analysis techniques. Thanks are also expressed to Irene Wainwright, Ervin Slansky and Rad Vertical trends in the mineralogy of the shales in the sequence Flossman, of the University of New South Wales, and John Levy of suggest an upward decrease in the abundance of non-kaolinite clay CSIRO Energy Technology, for assistance with the laboratory studies, minerals, relative to kaolinite, and also a progressive upward decrease and to Adrian Hutton of the University of Wollongong for advice on in feldspar abundance, suggesting a changing sediment source as the the identification of the maceral components. The assistance of Henrik basin was filled. Calcite, thought to be mainly of authigenic origin, is Petersen and an anonymous reviewer is also acknowledged for also more abundant in the middle and upper parts of the succession. constructive comment on the manuscript. Author's personal copy

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