Productivity control on oil shale formation—Mae Sot Basin, Thailand

~

Org. Geochem. Vol. 21, No. I, pp. 67 89, 1994

Pergamon

Copyright © 1994 Elsevier Science Ltd Printed in Great Britain. All rights reserved 0146-6380/94 $6.00 + 0.00

Productivity control on oil shale formation--Mae Sot Basin, Thailand JOSEPH A. CURIALEl and MARTIN R. GIBLING2 Unocal Energy Resources Division, P.O. Box 76, Brea, CA 92621, U.S.A. and 2Department of Earth Sciences, Dalhousie University, Halifax, Nova Scotia, Canada B3H 3J5 (Received 4 January 1993; returned for revision 30 March 1993; accepted in revised form 4 May 1993)

Abstract--Neogene oil shales from the freshwater, lacustrine, intermontane Mae Sot Basin, western Thailand, are examined in order to define (a) oil source rock potential, (b) variations in molecular and isotopic geochemical characteristics, and (c) the influence on source potential of organic matter productivity and preservation. Twelve samples spanning 7 m of section were examined using conventional isotopic, molecular, and organic petrographic methods of geochemical analysis; temporal resolution is 2700 yr per sample. Because thermal maturity differences and fluid migration within the sample set are absent, and organic matter type input variation is either minor or absent (based on visual kerogen analysis), we propose that organic matter differences among the samples are caused by variability in surface-water productivity. All samples are excellent potential source rocks (VR = 0.44).5% Ro) containing Types I and 11 organic matter (modified van Krevelen plot determination) consisting of almost 100% fluorescent amorphous kerogen (visual kerogen determination). Numerous diagnostic molecular markers and characteristics are present, including perhydro-fl-carotene, dammaranes, norsterane(s), and novel distributions of tricyclic terpanes. Stable carbon isotope ratios of kerogens and extract fractions range over 5%0, and co-vary with hydrogen index. This covariance is attributed to temporal increases in surface-water productivity leading to CO2-1imiting conditions and consequent increase in 6t3C of the organic matter in the photic zone. During times of elevated productivity, increased amounts of ~3C-enriched organic matter reached the water sediment interface. Thus times of greater productivity are accompanied by higher fi~3C and hydrogen index values, with 6 ~3C related to productivity under CO2-1imiting conditions, and H1 related to the relative amount of the water column that was anoxic during deposition. Our findings suggest that, in petroleum geochemical studies involving lacustrine source rocks, fi t3C values must be used with caution as oil oil and oil-source rock correlation parameters,

Key words--oil shale, Thailand, Mae Sot Basin, intermontane, lacustrine, productivity controls, preservation of organic matter, carbon dioxide limitations, organic facies, dammarane, tricyclic terpanes

toward either input of hydrogen-rich components (e.g. botryococcenes from Botryococcus braunii--see Dubreuil et al., 1989, and references therein) or development of hypersaline conditions associated with elevated concentrations of only a few species (e.g. ten Haven et al., 1988). A second source of bias in previous studies arises from efforts to interpret organic facies variability when sample resolution is restricted. Although several recent studies have addressed the question of adequate sample resolution in marine source rock sequences (e.g. Wenger and Baker, 1986; Moldowan et aL, 1986; Curiale and Odermatt, 1989), there are few similarly detailed efforts in lacustrine sections (Olsen et al., 1990; Collister et al., 1992). This has resulted in interpretation of organic facies variations in vast amounts of lacustrine section using only a few (possibly nonrepresentative) samples. Such an approach can hamper the integration of lacustrine-derived geological and geochemical data sets necessary to deduce the depositional setting. In this paper, we present integrated data for a selected suite of oil shales from the Mae Sot Basin of

INTRODUCTION

Understanding of petroleum source rocks formed in lacustrine settings generally has lagged behind that for marine source rocks. This results from the perception that lacustrine basins are less desirable than marine basins as exploration targets because they are smaller. However, among the organic geochemical community it has been long recognized that algal-rich lacustrine source rocks will generate, on a weight-forweight basis, considerably more oil than marine source rocks. This observation arose from the earliest work on kerogen typing, which established that most Type I oil-prone kerogens were deposited in lacustrine settings (Tissot and Welte, 1984). It is also clear that many lacustrine sediments are neither algal-rich nor oil-prone (Powell, 1986; Curiale and Stout, 1994), and that exploration and research efforts of petroleum geologists and goechemists have been biased in two respects. First, investigations have emphasized those lacustrine sediments containing hydrogen-rich kerogens. Many recent geochemical studies of lacustrine sections have been directed 67

68

JOSEPHA. CURIALEand MARTINR. GIBLING

Thailand (Fig. l). We seek to define the oil source rock potential of Mae Sot shale samples using detailed organic geochemical data, confirming and expanding previous sedimentological and petrological studies (Sherwood et al., 1984: Gibling et al., 1985a, b). We also integrate detailed molecular and isotopic data in the Mae Sot shales (1 sample per 58 Cln) with the previously published sedimentological results. This approach includes an effort to recognize temporal ~ariations (approx. 1 sample per 2700 yr) in organic facies. A second objective of our study is to examine the controversy on the relative importance of organic matter productivity versus preservation (Calvert, 1987: Calvert et al., 1991, 1992). The Mac Sot samples constitute a novel sample suite for such a study because several important geochemical processes are invariant throughout

--

20ON

--

18 °

the sample set, including thermal maturation (only 7 m of section are considered), fluid migration (the sampled section is thermally immature) and possibly organic facies. PREVIOUS GEOLOGICALAND GEOCHEMICAl.ST[DIES Cenozoic basins are widespread in Thailand (Fig. 1) and contiguous onshore and ofl;hore parts of southeastern Asia (Gibling, 1988). Basin development in the region reflects Himalayan collisional events that were associated with transcurrent displacement of large tectonic segments (Tapponnier et al., 1982; Le Dain et al., 1984: Burri. 1989), as well as sea-floor spreading in the Andaman Sea and South China Sea (Rodolfo, 1969; Ben-Avraham and Uyeda, 1973). Structural studies indicate that many basins

Myanr (Burn

--

16 °

0

k~

Fig. 1. Major Cenozoic basins and some major faults of northern and central Thailand. Recent work m the Chao Phraya Basin (O'Leary and Hill, 1989) indicates that numerous subsidiary basins ar~_'buried beneath tile late Cenozoic cover. Geothermal gradients from Thienprasert et al. (1978). Oillields from Burri (1989). Modified from Fig. 2 of Gibling (1988).

Productivity control on oil shale formation are half-grabens associated with both strike- and dip-slip faults (Knox and Wakefield, 1983; Flint et al., 1988, 1989; Stokes, 1988; Burri, 1989; O'Leary and Hill, 1989). Geothermal gradients average 40-60cC/km, locally up to 73°C/km under the Gulf of Thailand (Paul and Lian, 1975; Trevena and Clark, 1986). They average 30-40°C/km in onshore basins (Burri, 1989) with provisional values of 91°C/km recorded at Mae Sot and 93°C/kin at Fang (Barr et al., 1978; Thienprasert et al., 1978) (Fig. 1). The basins contain up to 8 km of Oligocene to Recent sediments that are largely lacustrine and fluvial in onshore, intermontane basins (Gibling et al., 1985a, b; Burri, 1989) but include marine strata in basins under the Gulf of Thailand (Woollands and Haw, 1976). Oil fields are known in at least four onshore basins (Fig. 1), and Flint et al. (1988) confirmed that the Sirikit oil field in the Phitsanulok Basin was sourced from organic-rich, lacustrine rocks (Rigby et al., 1992). The Neogene and uppermost Paleogene sections in several Thai intermontane basins contain algal-rich "'oil shale" sequences. The algal debris derives from P e d i a s t r u m and Botryococcus, and is found in shales and carbonate-rich rocks with Fischer Assay yields averaging more than 12gal/ton, and exceeding 80gal/ton in some locations (Chakrabarti, 1976; Gibling et al., 1985a, b). Whole rock organic petrographic analyses by Sherwood et al. (1984) indicate that these carbonates/shales contain organic matter dominated by lamalginite (defined by Sherwood et al., 1984, p, 48, as "thin lamellar or filamentous alginite"). The oil shale deposit of the Mae Sot Basin (Fig. 2) is the largest documented in Thailand, and much of the published geochemical work on the country's intermontane basins has concentrated on Mae Sot (Sherwood et al., 1984; Gibling et al., 1985b; Stokes, 1988: Bjoroy et al., 1988). Although this basin extends into neighbouring Myanmar (Burma) as the Htichara Basin (Stokes, 1988), the oil shales in this western portion have been investigated only sparingly (Cotter, 1923). Work summarized by Gibling et aL (1985b) indicates that average oil shale retort yields range from about 40 gal/ton for the highest grade material (type A) to less than 10gal/ton (type D). Yields for intercalated maristones are less than 5 gal/ton. Organic richness is roughly inversely proportional to carbonate content (Smith et aL, 1959; Gibling et al., 1985b), and certain elemental concentrations (e.g. Fe, P, Cu, Zn) are greater in the higher grade shales (Gibling et al., 1985b). Sulfur content of the high grade shale oil is approx. 0.4% (Smith et al., 1959). Conventional source rock methods (i.e. total organic carbon analysis and Rock-Eval pyrolysis) and modern methods of hydrous pyrolysis and molecular analysis were applied to the Mae Sot oil shales by Bjoroy et al. (1988). They examined five core samples (maximum depth of 677m) having total organic

69

carbon contents and hydrogen indices of 3.4-8.5% and 499-659 rag/g, respectively. The samples were liptinite-rich, contained up to 2500ppm hydrocarbons, and were thermally immature (VR = 0.270.33% Ro). Up to 7% of the rock weight was converted to soluble organic matter by hydrous pyrolysis, representing a conversion of greater than 80% of the organic carbon. Such values concur with shale retort conversions of Mac Sot organic material to oil of up to 62% (Smith et al., 1959). These results are consistent with previous sedimentological work, and imply a hydrogen-rich, world-class oil source rock, containing Type I kerogen that is even more oil-prone than the "type section" Type I kerogen of the Green River Formation, Utah (Sherwood et al., 1984). Although Bjoroy et al. (1988) presented the only detailed molecular data for the Mac Sot shales known to us, Lawwongnagam and Philp (1991) studied oils produced from the Sirikit Field in the Phitsanulok Basin, about 100 km east of Mae Sot (Rigby et al., 1992). This field has produced up to 15,000-20,000 BOPD from fluvio-lacustrine sandstones (Knox and Wakefield, 1983; Soeparjadi et al., 1985; Flint et al., 1988). From detailed molecular analyses of these oils, Lawwongnagam and Philp (1991) concluded that the organic matter in their source rock(s) consists of a mixture of bacterial, algal and land-plant components, deposited in relatively oxic conditions. Stable carbon isotope values of the aliphatic and aromatic hydrocarbon fractions average -30.3 and -29.7%o, respectively (these values are about 2-3%0 lighter than those reported for Mae Sot kerogens-see Lewan, 1986). Lawwongnagam and Philp (1991) noted that molecular maturity parameters in the Sirikit oils imply that they were sourced from relatively immature source rocks. This observation is of particular interest because of the high heating rates that have been interpreted for the central Thai intermontane basins (as noted earlier). MAE SOT BASIN---GEOLOGIC OVERVIEW

The Mae Sot Basin is located in central Thailand, straddling the border with Myanmar (Burma; Fig. 2). Details of the basin geology are summarized by Gibling et al. (1985b). The modern basin is 65 km long by 35 km wide (41 x 22 mi), but gravity data suggest the presence in the sub-surface of at least two sub-basins (Fig. 2). The deepest drill hole in the basin penetrated only 833 m (2733 feet) of Cenozoic strata, which may thicken toward the fault-bounded eastern margin (Stokes, 1988); drilling failed to reach basement. Fossils from exposed strata suggest late Miocene to Pleistocene ages. There is currently little information concerning the nature and age of deeper basinal strata or the basin's tectonic history. Strata studied in surface outcrops and shallow pits near the village of Ban Wang Kaew (Fig. 2) (Gibling et al., 1985b) include two oil shale sequences up to

70

JOSEPH A. CURIALE and MARTIN R. GIBLIN(;

98o20 '

98030 '

98040 '

Fig. 2. Extent and topographic setting of the Mae Sot Basin. The Moei River is the border between Thailand and Myanmar. Bouguer anomaly data are from the Thai Department of Mineral Resources. Basin margin east of Mae Sot is interpreted as a major fault (Stokes, 1988). Modified from Gibling et al. (1985b).

10 m thick which contain a macrofossil assemblage of fish, snakes, ostracods, insects and woody material. These strata were interpreted as perennial, stratified lake deposits on the basis of the rhythmic lamination, the predominantly nektonic biota, and the scarcity of bioturbation. An intervening marlstone/sandstone succession 70m thick contains an assemblage of gastropods and unidentified burrowers. The succession was interpreted as the deposits of shallow perennial lakes and subaerially exposed flats on the basis of the biota, channel-based sandstones and desiccation cracks. Drill hole DDH 3-5 in the study area penetrated 495m (1645 feet) of strata, and the drillers' logs suggest the presence of numerous oil shale sequences near the base of the well.

The upper oil shale sequence was sampled in four pits 2m 2 by 5m deep and about 50m apart that exposed the entire sequence. The pits yielded 600 slabs several centimeters thick and about l kg in weight that were sealed in plastic bags immediately after excavation and stored indoors since 1980. The upper oil shale sequence was divided into five rock types based on hand specimen appearance supplemented by geological and geochemical analyses (Table 1). The four oil shale types and the marlstone form a gradational series, and are composed of fine-grained carbonates (calcite and Fe-rich dolomite) and silicates (quartz, K-feldspar, plagioclase~ analcite, illite and smectite). In mineralogical terms, the higher yield oil shales are dolomitic and calcitic

71

Productivity control on oil shale formation Table I. Rock types from Upper Oil Shale Sequence, Mae Sot Basin~ Mean SG ~

LOP wt%

Yield~ Mean

Yieldr Max

A

1.67

23.9

168

341

B

1.86

20.9

116

224

C

2.07

8.8

43

115

Gray to grayish brown to oli',e gray

D

2.20

5.3

37

183

Gray to olive gray to pale yellow

0.670

Marlstone

2.36

4.3

17

32

Light gray to light olive gray to pale yellow Grayish brown

0.746

Rock type h

Laminated siltstone

--

Couplet thickness h

Colorg Dark gray to dark reddish brown Dark grayish brown

Comments

"] 0.080

Forms high-yield units up to 1.5 m thick; uniformly dark; B with pale laminae Forms units up to 0.5m thick: comprises dark and pale bands up to I cm thick Mainly pale with well-defined couplets; forms bulk of the upper oil shale sequence Uniformly pale: couplets diffuse or absent Thin (< 5 cm), abruptly based beds with parallel lamination and ripple cross-lamination in form sets: density-flow deposits

a - Analytical results based on 60 samples. Data from Gibling et al. (1985b). b - A D indicate oil shale grades of Gibling et al. (1985b). c = Mean specific gravity. d - Mean loss on ignition (principally from organic carbon) on heating at 550 C for 2 h. e - Mean oil yield (L/MT). Based on Fischer Assay results. f = Maximum oil yield (L/MTI. Based on Fischer Assay results. g - Major categories from Munsell Soil Color Chart (1975). h - Mean couplet thickness (mm). m u d s t o n e s , rich in analcite, w h e r e a s t h e lower yield s h a l e s a n d t h e m a r l s t o n e s are calcitic c a r b o n a t e s with a d m i x t u r e s o f t e r r i g e n o u s m i n e r a l s . All five types, except s o m e u n s t r a t i f i e d m a r l s t o n e s , are finely l a m i n a t e d , w i t h a n o r g a n i c - r i c h l a m i n a 10 20 m m t h i c k a n d a m i n e r a l - r i c h l a m i n a u p to 2 m m t h i c k (Fig. 3). T h e s e l a m i n a e are c o m p o s e d o f c o u p l e t s w h o s e thickn e s s c o r r e l a t e s with r o c k type ( T a b l e !). T h e c o u p l e t s p r o b a b l y reflect s e a s o n a l ( m o n o s o o n a l ? ) s e d i m e n t a tional p a t t e r n s w i t h i n t h e p e r e n n i a l lakes. A s s u m i n g t h a t t h e c o u p l e t s are s e a s o n a l in origin, G i b l i n g e t al. (1985b) e s t i m a t e d t h a t the u p p e r oil s h a l e s e q u e n c e w a s laid d o w n in 46,000 yr. A t B a n W a n g K a e w , 12 s a m p l e s were selected to s p a n t h e u p p e r oil s h a l e s e q u e n c e , with t w o e a c h o f oil s h a l e s A - C a n d six o f

oil s h a l e D , t h e p r e d o m i n a n t rock type (Fig. 4). T h i n b e d s o f l a m i n a t e d s i l t s t o n e with c u r r e n t - f o r m e d s t r u c t u r e s a r e i n t e r c a l a t e d with oil s h a l e s A - C a n d a r e i n t e r p r e t e d as d e n s i t y - f l o w d e p o s i t s laid d o w n in o f f s h o r e p a r t s o f t h e lake. EXPERIMENTAL METHODS S a m p l e s were c r u s h e d a n d p o w d e r e d p r i o r to a n a l y s i s for total o r g a n i c c a r b o n ( T O C ) a n d R o c k Eval p y r o l y s i s yield. R e s u l t s are listed in T a b l e 2. A t t e m p t s were m a d e to a s s e s s t h e r m a l m a t u r i t y u s i n g b o t h Tm~x R o c k - E v a l v a l u e s a n d vitrinite reflectance (VR). All V R a n a l y s e s were c o m p l e t e d o n w h o l e rock p r e p a r a t i o n s , a n d are listed as r a n d o m V R values.

Fig. 3. Sample of oil shale D from upper oil shale sequence. Note the rhythmic lamination with well-developed couplets and bands of darker and paler shale with thinner and thicker couplets, respectively, a = loop bedding (probably formed by syneresis or early diagenetic deformation; Cole and Picard, 1975); b = contorted stratification; e = 3 m m layer of coarse carbonate (probably a thin densityflow deposit).

72

JOSEPHA. CURIALEand MARTINR. GIBLING m

Sample

Oil Shale

0

Number

Type

• 202-19

A

• 202-32

B C

• 202-38

2

• 202-64

• 204-18

B

3

• 204-21

C

• 204-35

D

4

A

I

5

•

204-56

•

204-61

D D

• 204-71

D

204A-34

6

D D

- -

7

m

%

_ _ i - m - - %

~

_

.,.,."--" - -

_

i _ _ n

- -

Oil shale A-B =--

8

Oil shale C Oil s h a l e D

Marlstone

Laminated

siltstone

Fig. 4. Upper oil shale sequence at Ban Wang Kaew, based on pit sections. Although the Tin,x values are considered valid (because $2 yields were sufficient in all cases), VR values are questionable due to extremely small vitrinite concentrations in the whole rock preparation (as noted later, vitrinite, based on visual kerogen analyses. constitutes only 0-2% of the kerogen in these samples). The number of vitrinite particles counted is listed in the last column of Table 2, and ranges from 2 to 9. These counts are considerably below the 20 particles recommended for whole-rock VR measurements. Kerogens were prepared from solvent-extracted rocks (see later) using HCI/HF acid digestion followed by heavy liquid separation (1.85 specific gravity ZnBr 2 solution). Each kerogen was subsequently re-extracted with acetone prior to analysis. Demineralization procedures were probably inefficient for several of the Mae Sot oil shales because of extremely high concentrations of fluorescent amor-

phous organic matter (referred to as fluoramorphinile in this report; Largeau et al., 1990; Thompson and Dembicki, 1986). Petrographic point counting (100 counts) of kerogens was completed by GeoOptics Ltd (Newcastle, U.K.). Results are reported in Table 3 according to visual kerogen type (I--IV). Quantitative pyrolysis-gas chromatographic analyses (PGC) were completed on all kerogens; poly-tert-butyl-styrene was used as an internal standard (added at 0.25% w/w of the kerogen; after Larter and Senftle, 1985). Pyrolysis details and data processing information are reported by Curiale and Stout (1993). Powdered samples were extracted using a ternary mixture of toluene, acetone and methanol (70/15/15, v/v/v) at room temperature for 24 h. Extractable organic matter (EOM) yields are listed in Table 4 in parts per million (w/w). Asphaltenes were precipitated in excess (100:1) hot n-heptane. Heptane-

Productivity control on oil shale formation

73

Table 2. Sample information, source rock potential and thermal maturity ~ Sample

b

202-19 202-32 202-38 202-64 204-18 2/14-21 204-35 204-56 204-61 204-71 204A-34 203-6

0.70 1.00 120 1.90 2,85 2,90 350 4.20 4.40 4.85 6.60 7.60

A B C A B C D D D D D D

TOC (%)

SI (mg/g)

S2 (mg/g)

S3 (rag/g)

Tma~ ('C)

H1 (mg/g)

O1 (mg/g)

22,40 12.51 4.23 18.76 16,37 10.01 0.94 1.22 0.89 3.06 1.44 2,96

7.85 7.06 2.17 7.76 7.78 4.76 0.25 0.34 0,28 1.03 0.34 0,83

225,61 105,48 34.42 195.64 137.46 80.26 4,36 5.57 4.68 25.26 8.42 21.35

2.60 3.00 1.60 2.46 4.27 3,47 1,14 1.19 0.92 1.26 1.23 1.87

437 417 408 433 427 422 424 417 413 412 422 424

1007 843 814 1043 840 802 464 457 526 825 585 721

12 24 38 13 26 35 121 98 103 41 85 63

VR ( % R o) 0.03 0.06 0.06 0+04 I).05 0.06 0.05 0.06 (I,06 0.04 0.04 0.04

0.40 0.43 0.48 0.36 0.37

J 4 I 3 4

c 0.48

5

0.44

2

a - Source rock potential data include total organic carbon (TOC), Rock-Eval yields (S~, S 2, $3), Tin, X, hydrogen index (HI), oxygen index (O1) and production index [ P I - St/(S ~ + $2)]. Maturity is measured by whole-rock vitrinite reflectance (VR). b = Relative depth from the top of the section, in meters. c = Oil shale category, based on lithology (Gibling et al., 1985a, b). d - N u m b e r of vitrinite particles counted in V R determination. Note that past experience indicates that a reading of 20 particles or more is optimal. e N o measurable vitrinite was observed in whole-rock preparation.

soluble material was separated into hydrocarbon and NSO (nitrogen-, sulfur, and oxygen-containing) fractions over silica gel (4% H20), respectively eluting with toluene/n-pentane (2.5:97.5; w/w) and toluene/ methanol (50:50; w/w). The hydrocarbon fraction was separated into aliphatic and aromatic hydrocarbons using n-pentane and dichloromethane, respectively, over a calcined (120'C, 24 h) silica gel column. Fraction data are listed in Table 4 as a percentage of EOM. Stable carbon isotope ratios were determined on the EOM and on each of the four EOM fractions. Samples were tube-combusted (Geoscience Analytical, lnc., Simi Valley, CA) and CO2 was analyzed on a Finnigan MAT 251 instrument. Data in Table 4 are reported relative to the PDB standard, and are precise to approx. _+0.05%0 (absolute). Aliphatic and aromatic hydrocarbon fractions were analyzed using gas chromatography (GC), according to conditions outlined in Curiale (1987) and references therein. Helium was used as the carrier gas. Data were processed using the VG MULTICHROM package on a VAX minicomputer. Several gas chro-

matography-mass spectrometry (GCMS) experiments were conducted, all using an HP 5890 GC interfaced to a VG 70-250SE mass spectrometer. Oven conditions and other instrument parameters are described by Curiale and Stout (19931. Primary data were collected by whole-extract injection, using selected ion recording (SIR) methods and a spectrometer resolution of approx. 5000. In addition, full scan GCMS analyses were completed on the silicalitesieved branched and cyclic aliphatic hydrocarbon fractions of selected samples. Each sample was also examined in two different metastable transition GCMS experiments, one to monitor the transitions of the sterane parents to m/z 217 and 231, and another to monitor the transitions of the hopane parents to m/z 177 and 191. Compound identifications (corresponding to selected figures) are listed in Table 5. The molecular ratios (reported in Table 6) were computed from peak heights (cf. Kipiniak, 1981; Park et al., 1987) on either gas chromatograms, SIR mass chromatograms, or metastable transition chromatograms, as indicated. HYDROCARBON

Table 3. Kerogen maceral and isotope data ~ Sample

Grade

l

II

III

IV

613Cker (%0)

6 t3Ccarb (%o)

202-19 2112-32 21)2-3~ 202-64 2114-1~< 204-21 21)4-3 ~, 204-56 204-61 204-71 204A-34 203-6

A B C A B C D D D D D D

0 0 0 0 0 0 I) 0 0 5 25 5

100 99 100 97 100 100 98 10(I 9 t~ 95 75 95

0 0 0 2 0 0 2 0 1 0 0 0

0 1 0 l 0 0 0 0 0 0 0 0

- 28.6 -25.4 - 26.0 - 20.6 -23.5 -24.7 26.2 -28.5 - 27,7 -27.0 -27.0 25.3

9,6 8.7 5.6 7.8 4.4 5,3 2,0 2,9 1,2 2.3 4.9 2.4

a ~ Kerogen type (for types I, I1, III and IV) is presented as a percentage of total kerogen macerals. Several macerals are defined in the visual kerogen determination (Curiale and Stoat, 19931, however for these samples only one kind of maceral was present in each kerogen type, as follows: Type I is all alginite; Type 11 is all fluoramorphinite (Senftle et ul,, 1987); Type 11I is all vitrinite; Type IV is all intertinite.

SOURCE ROCK CHARACTER

Total organic carbon (TOC) contents for the Mae Sot oil shales (Table 2) generally parallel the oil shale grade classification of Gibling (1985a, b, 19881, with grade A shales having the highest TOC values (18.76-22.40%) and grade D shales having the lowest (0.94-3.06%). The distribution of TOC according to oil shale grade is shown in the depth-TOC distribution in Fig. 5. Organic carbon content diminishes significantly at about 3 m below the top of the section. Rock-Eval pyrolysis yields (S~ + S:) are sufficient to conclude that all samples are potential oil source rocks (Table 2). As shown in Fig. 5, $2 yields also correspond to oil shale grade, with the highest grade shales having yields of about 200 mg/g (i.e. 20 wt% of the rock is converted to hydrocarbons on heating from 300 to 550 C at 25 C/min).

74

JOSEPH A. CURIALE a n d MARTIN R. GIBLING Table 4. Extractable organic matter data ~ EOM (ppm)

Aliph (%)

Arom (%)

NSO (%)

Asph (%)

~ [3CEoM

Sample

Shale grade

(%~)

~ 13C~liph t~I3c..... (%)

(%o)

613CNso (Too)

t~13Casph (%)

202-19 202-32 202-38 202-64 204-18 204-21 204-35 204-56 204-61 204-71 204A-34 203-6

A B C A B C D D D D D D

12,276 23,523 9219 14,516 33,908 13,393 848 2002 1170 4979 1068 2699

20.6 6.5 12.1 16.9 8.4 6.7 2.8 10.9 11.7 9.9 13.0 7.1

8.9 4.9 6.1 10.7 1.3 2.1 5.6 2.5 3.9 3.1 1.6 1.0

48.8 63.8 55.7 61.3 50.8 53.4 62.6 58.1 56.7 67.0 50.6 57.5

21.7 24.9 26.1 I1.1 39.5 37.8 29.0 28.5 27.7 20.0 34.9 34.4

-27.5 - 27.2 -28.0 -25.7 25.9 -26.1 -28.9 -30.3 29.3 28.l -28.1 27.5

-28.2 - 28.6 -28.8 -27.5 -27.9 --28.0 -.-29.4 -30.6 29.7 29.1 -29.1 -28.0

-26.0 - 26.6 26.8 -25.8 25.4 25.3 -28.4 29.9 29.4 28.5 -27.2 -26.2

-27.8 27.5 28.3 25.6 26.6 26.6 26.6 30.7 29.5 28.2 28.5 - 28.0

-27.3 - 26.0 26.9 23.1 24.5 25.1 --28.3 29.3 28.4 26.7 --27.5 -26.4

a = Gravimetric distribution (as a percentage of total extractable organic matter--EOM) and stable carbon isotope ratios (PDB) for the aliphatic hydrocarbon (aliph), aromatic hydrocarbon (arom), nitrogen-, sulfur- and oxygen-containing tNSO), and asphaltene (aspht fractions of the EOM.

As expected, shale grades decrease in HI yield (and increase in O1 yields; Fig. 6) in an orderly fashion, with grade A having the highest HI (and thus the best oil source rock potential). As we propose in a later section, the variation in hydrogen and oxygen indices is due to differences in surface productivity and extent of organic matter preservation during settling in the water column. The linear trend in Fig. 6 may be interpreted alternatively as (a) influenced by carbonate minerals, or (b) a mixing curve, reflecting temporal changes in depositional environment and the type(s) of organic matter comprising these oil shales. The first possibility is rejected because of the absence of an OI-CaCO3 relationship. The second possibility, the progressive dilution with terrigenous (land-plant) components, could account for the systematic decrease in HI (and increase in OI). However, although a few woody fragments were noted on bedding planes Table 5. Compound identification Code a b c d e f g h i

J k 1

m

o P q r s !

u v w x Y

Compound Pristane Phytane Tricyclic terpane (C20H36; Chicarelli et al., 1988) Tricyclic terpane (C2~H38; Hall and Douglas, 1983) Norsterane (C23H40; Hall and Douglas, 1983) Tricyclic terpane (C26H48; Ekweozor and Strausz, 1983) Methylsterenes? (P = 398; B = 231) Unknown ctot~tR-C27 sterane Dammar-13(17)-ene (Meunier-Christmann et al., 1991) Hopene and unidentified C30 tricyclic terpane (C30Hs6; Ekweozor and Strausz, 1983) ~tctctg-c2~ sterane /%taR-C2,~ sterane; 20S- 13fl, 17~t-dammarane (Meunier-Christmannet aL, 1991); and C30 tricyclic terpane (C3oH56; Ekweozor andStrausz, 1983) 20R- 13~. 17~t-dammarane (Meunier-Christmann et al., 1991) ~:t~R-('2,) sterane Hop- 17(21)-ene Hopane (co-elutes with n-C3~ ) Moretane fib -hopane Homohop-30-ene [3[3-homohopane [3fl-bishomohopane (van Dorsselaer, 1975) Perhydro-[3-carotene (Murphy et al., 1967) Carotenoid (C3~H74; tentative) Unknown

of some oil shale slabs (Gibling et al., 1985b), evidence for land plant input was minimal in visual kerogen examinations (Table 3). We also infer that chemical variations at the water-sediment interface are not a controlling factor here, based on (a) similarity among kerogen maceral distributions (Table 3), and (b) the occurrence of fine laminae throughout the section (Fig. 3; see also Gibling et al., 1985b). Nevertheless, maceral distribution and laminae extent are coarse measurements, and HI variability may result from more subtle changes, such as a fluctuating input of bacterial biomass. Because of uncertainties such as these, we do not consider the issue to be resolved. In general we feel that the visual kerogen typing scheme delineated in Table 3 should be considered independently from the c h e m i c a l source rock typing scheme of Fig. 6 (Powell, 1986: Powell et al., 1991). That is, although relationships may exist between fluoramorphinite content and HI, wc do not expect a necessary correspondence between them (Senftle et al., 1987; Murchison, 1987). In any event, because our interest is focused on source rock potential of the Mae Sot oil shales (rather than visual kerogen analysis), and because this potential is best defined by the van Krevelen (i.e. chemical) scheme for source rock assessment generated by Rock-Eval (Fig. 6), we emphasize Rock-Eval data as our best source rock tool. On this basis, we can summarize that the Mae Sot oil shales are Type I potential source rocks (including oil shale grades A, B and C) and Type II potential source rocks (including oil shale grade D), and that oil source rock potential increases systematically in the grade order D, C, B, A. Although both Tin,~ and VR are available as thermal maturity indicators, VR values are speculative because of low vitrinite contents. The Tm~x data in Table 2 imply that (a) the samplc set is thermally immature, and (b) as expected, there is no relationship between depth in the section and Tm,x. Thermal immaturity in the sample set is suggested by low Tm,~ values (mean=421-C, standard deviation=8°C) (Tissot and Welte, 1984), and supported by low production indices [PI=S~/(S~ +$2) ] of 0.03~3.06. Furthermore, Tn~x values in Table 2 are consistent

Productivity control on oil shale formation

75

Table 6. Molecular data a Sample

b

c

d

e

f

g

h

i

j

k

1

202-19 202-32 202-38 202-64 204-18 204-21 204-35 204-56 204-61 204-71 204A-34 203-6

9.49 10.15 7.62 2.73 9.70 7.81 2.89 1.21 1.18 2.20 2.43 3.44

21 15 20 23 14 25 24 35 29 18 19 19

19 16 20 13 I1 26 23 19 20 16 14 16

60 68 60 64 75 48 53 46 51 66 67 64

0.62 0.91 0.92 0.15 2.14 0.53 1.67 1.15 1.81 2.13 1.10 1.09

0.27 0.32 0.28 0.30 0.24 0.22 0.23 0.22 0.22 0.26 0.25 0.27

0.11 0.05 0.03 0.12 0.02 0.06 0.05 0.05 0.05 0.03 0.03 0.04

0.05 0.06 0.22 0.19 0.10 0.10 0.17 0.05 0.22 0.19 0.12 0.34

37.2 40.8 40.7 38.0 36.0 41.1 47.3 44.3 43.4 30.3 30.2 45.3

55.2 53.4 43.9 25.6 35.1 37.9 28.2 42.3 36.3 54.1 56.8 37.8

7.6 5.7 15.3 36.4 28.9 21.0 24.5 13.5 20.3 15.6 13.0 16.9

a = All ratios are measured from peak heights on mass chromatograms of GCMS-SIR runs (see text) at medium-resolution (5000), unless otherwise noted. b = n-C29/5et(H),14~(H),17=(H),20R-cholestane (measured from peak heights on aliphatic hydrocarbon gas chromatograms). c = 5~t(H),14ct(H),17a(H),20R-cholestaoe [normalized to total 5~t(H),I4~t(H),I7ct(H),20R C27.29 steranes]. d-5:t(H),14¢(H),17ct(H),20R-24-methylcholestane [normalized to total 5ct(H),14ct(H),17ct(H),20R C27:9 steranes]. e = 5:t (h), 14~t(H), 17~t(H),20R-24-ethylcholestane [normalized to total 5¢ (H), 14~(H), 17ct(H),20R C27 29steranes]. f = 5~t(H),14a (H),I 7~t(H),20R-24-ethylcholestane/17~ (H),21/~(H)-hopane. g = 5fl(H), 14~t(H),I 7~t(H)-24-ethylcholestane/5~t(H), 14~t(H), 17ct(H),20R-24-ethylcholestane (measured from the m / z 40(~ > 217 metastable transition chromatogram). h = 20S/(20S + 20R)-5=(H),14ct(H),17~t(H),20R-24-ethylcholestane. i = 22S/(22S + 22R)-30-homohopane (measured from the m / z 426-> 191 metastable transition chromatogram). j = 17ct(H),21fl(H)-hopane (normalized to total ~fl +flct + tiff hopanes; measured from the m / z 412-> 191 metastable transition chromatogram). k = 17fl(H),21ct(H)-hopane (normalized to total ctfl + flct +tiff hopanes; measured from the m / z 412-> 191 metastable transition chromatogram). I= 17fl(H),21fl(H)-hopane (normalized to total ~tfl+ flct +fl,B hopanes; measured from the m / z 412-> 191 metastable transition chromatogram).

f i o m a low o f - 2 9 . 3 % 0 (202-56) to a high o f - 2 3 . 1 % o (202-64), a n d this 6.2%0 r a n g e is typical f o r the E O M a n d each o f its fractions. As p r o p o s e d b e l o w in greater detail, this wide r a n g e m a y be c a u s e d by v a r i a t i o n in surface p r o d u c t i v i t y (i.e. in the a m o u n t o f b i o m a s s p r o d u c e d ) o f the M a e Sot Lake(s), causing episodic C O ; - l i m i t i n g c o n d i t i o n s .

w i t h the V R values ( H e r o u x e t al., 1979), despite the small a m o u n t o f vitrinite in the samples. ISOTOPIC AND MOLECULAR RESULTS Stable c a r b o n i s o t o p e ratios (Table 3, Fig. 7) r a n g e widely for this d a t a set. F o r e x a m p l e , f ISCasph r a n g e s

0 1

•

A

2

y,

3

5 t21

6 7

8 9

0

5

10

15

TOC (%)

20

25

0

60

120

180

240

S 2 YIELD (mg/g)

Fig. 5. Variation of total organic carbon (TOC) and S2 Rock-Eval pyrolysis yield with composite section depth in the Mae Sot sample set. Oil shale grades are indicated by squares (A), circles (B), triangles (C) and diamonds (D). Shale grades are defined according to designations of Gibling et al. (1985a, b). tOG 21q --F

JOSEPH A. CURIALEand MARTINR. GIBLING

76

1200 1100 IOO0

700 600 500

200 100

0

0

20

40

60

80

100

120

OXYGEN INDEX (rag/g) Fig. 6. Modified van Krevelen diagram (hydrogen vs oxygen index) for Mae Sot sample set. Oil shale grades are indicated by squares (A), circles (B), triangles (C) and diamonds (D). Shale grades are defined according to designations of Gibling et al. (1985b). Note that even though the linear trend might suggest a progressive influx of terrigenous organic matter diluting algal-rich water column organic matter, other interpretations are possible (see text).

? ~

202-19(0.7Ore)

~

202-32 (1.~m)

~

202-64(1.90m)

~ ( 2 . 5 0 m )

>--.v/ % ~204-56(4.20m)

I.so>-L,s,. I

~-~204-61 (4.40m) ~-~4-71

-31

I

-29

]

J

l " ~"~'KEFI] SAMPLIE Dz=PTH

(4.85m)

]

I

-27 -25 -23 ~lS C (~)

]

-21

-19

Fig. 7. Galimov-type plots of stable carbon isotope ratios for selected organic matter fractions (kerogen and extractable organic matter sub-fractions) of the Mae Sot oil shale samples. Numbers to the right of each curve are the sample designation and depth in the composite section, as listed in Table 2. Abbreviations in the inset are: AL = aliphatic hydrocarbon fraction; AR=aromatic hydrocarbon fraction; NSO= nitrogen-, sulfur- and oxygencontaining compound fraction; ASPH = asphaltene fraction; KER = kerogen.

Pristane, phytane, tricyclic terpanes and perhydroB-carotene are the predominant molecular constituents of these shales. Figure 8 (upper panel) shows a typical gas chromatographic distribution, in this case for the aliphatic hydrocarbons of the EOM in sample 204-71 (4.85 m); compound identifications are presented in Table 5. The n-alkane concentration, relative to the branched and cyclic aliphatic components in Fig. 8, is low in this particular sample, although considerable variation occurs in the sample set (see Fig. 9). Note that the pristane/phytane ratio in this and other Mae Sot samples is less than unity (however, see data of Bjoroy et al., 1988), perhaps suggesting elevated salinity in the depositional environment (Luo et al., 1988). Although other evidence for saline lakewaters is available (e.g. gypsum lenses; Brown et al., 1951; Gibling, 1988), bedded evaporites have not been encountered. The most prominent peak in Fig. 8 is peak c, a C20H36 tricyclic terpane. A similar compound has been observed in various sample types by other workers (Chicarelli et al., 1988; Ekweozor and Strausz, 1983; Aquino Neto et al., 1983). Peak c is accompanied by peaks d (at least two compounds) and e, identified as two C2~ H38 tricyclic terpanes and a C23H40 norsterane (respectively). All three compounds were observed previously in a Permian oil shale from France by Hall and Douglas (1983). Their Permian shale also contains several carotenoid hydrocarbons (cf. Mae Sot peaks w and x in Fig. 8). In general, the distinction between samples of grade D and grades A, B and C in the source rock and isotopic data (Tables 2-4) is also evident in the

Productivity control on oil shale formation

77

70

60 204-71 4.85m 50

W

b _ 40 I

~-- 30

a

TIME (IN MINUTES Fig. 8. Gas chromatogram of the aliphatic hydrocarbon fraction for sample 204-71 (4.85 m composite depth). This sample is shown as representative of the entire oil shale sample set. The upper chromatogram shows most of the elution range for this fraction. The lower chromatogram is expanded in the 36-43 min elution range. N-alkanes are designated by a number above the peak corresponding to the number of carbon atoms in the chain; the n-alkane peaks are connected by a line. The shaded peaks in the lower chromatogram (i, 1 and o) are the C,7_29 5a(H),I4~(H),17~(H) steranes. All peak identities are given in Table 5. biomarker region for the sample set (Fig. 9), and can be seen most clearly when specific molecular ratios are plotted against depth. For example, the n-alkane to sterane ratio is significantly higher in the uppermost (richer) oil shales than in the deeper grade D shales (Fig. 10). The uppermost shales have nC~9/5~(H),14~(H),17~(H),20R-cholestane ratios of

7.6-10.2 (with one outlier at 2.7), whereas the lower shales have ratios of 1.2-3.4 (Table 6). Although this ratio may be interpreted as a "land plant/algal" ratio (i.e. higher ratios could imply a greater land plant contribution), the highest values are generally associated with the richest oil shales. The C29 n-alkane is not exclusively terrigenous (Clark and Blumer, 1967,

II

.

INTENSITY (mY)

INTENSITY(mY)

INTENSITY (mV)

iNTENSITY (mV)

i

'

T

,

i

,

,

,

i

INTENSITY (mV)

,

INTENSITY (mY) ,

,

*

~

•

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,

i

.

.

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r

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INTENSri'YmV)

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Productivity control on oil shale formation

79

0 1 2 3 v

E

4

m

5

i== 6

m

7 8 9

m

m

10

0

i

I,

I

I

I

I

I

I

I

I

I

1

2

3

4

5

6

7

8

9

10

11

n-C29/5o~ 14a, 17~, 20R-Cholestane

Fig. 10. Depth distribution of the n-C29/5a(H),14~t(H),17ct(H),20R-cholestane ratio in the Mac Sot composite section. Oil shale grades are indicated by squares (A), circles (B), triangles (C) and diamonds (D). Shale grades are defined according to designations of Gibling et al. (1985b). and many others), nor is 5~t(H),14ct(H),17~t(H),20Rcholestane exclusively algal (Voikman, 1988, and references therein). Indeed, the traditional interpretation of the C29-biased sterane carbon number distribution for these shales (Table 6) would indicate significant terrigenous organic matter in the samples, much more than is indicated by either whole-rock or kerogen-concentrate petrographic examination. Two C30 tricyclic terpanes (as co-eluting portions of peaks k and m; Table 5) are present in all samples (Figs 8 and 9). These compounds are among the more prominent members of the m / z 191 distribution. Although mass spectra of both compounds were difficult to obtain (due to co-elution uncertainties), they appear to be those C30 tricyclic compounds identified by Ekweozor and Strausz (1983) in Athabasca oil sand extracts (Canada). Tricyclic terpanes are found in almost all shale extracts worldwide, regardless of age (Aquino Neto et al., 1983), although they are particularly prominent in certain oil shales. They were identified originally in oil shales from the Eocene Green River Formation (western U.S.) by Anders and Robinson (1971) and Gallegos (1971). Certain of the compounds are common in oils from all depositional settings. Their origin is unclear,

although bacterial and algal sources are usually invoked (Aquino Neto et al., 1983, 1992; Chicarelli et a/., 1988). The occurrence of unusual distributions of tricyclic terpanes often coincides with the presence of carotenoids in oil shales (e.g. perhydro-fl-carotene, a major constituent of the Mae Sot shales, is present also in Green River samples--see Murphy et aL, 1967). Other confirmed and suspected bacterially-derived components occur in the Mae Sot oil shale samples, including the ubiquitous hopanoids and at least two dammaranes. Peak n and part of peak m (Table 5; Figs 8 and 9) are 20R and 20S 13/~(H),17ct(H)dammarane, respectively (based on retention times and comparison with published spectra; MeunierChristmann et al., 1991). In addition, dammarenes [A13t17)]may also be present (the "j" peaks in Fig. 8). A typical mass chromatographic fingerprint for these components is shown in Fig. I 1. The dammaranes and dammarenes are present in all samples, and their concentrations tend to co-vary with the concentration of the hopanoids. The thermal maturities of the Mae Sot samples are apparent in molecular data shown in Figs 8, 9 and 12. Unsaturated and fl[3 hopanoids (peaks p, t, x, u and v; Figs 8, 9 and the upper panel of 12), dammar-

Fig. 9. Portion of aliphatic hydrocarbon gas chromatogram (36~3 min) for each Mac Sot oil shale extract examined in this study. The sample designation, composite section depth and oil shale grade (Gibling et al., 1985b) are listed at the top fight of each ehromatogram. N-alkanes are designated by a number above the peak corresponding to the number of carbon atoms in the chain; the n-alkane peaks are connected by a line. The shaded peaks (i, I and o) are the C27_295~(H),14a(H),17ct(H) steranes. All peak identities are given in Table 5.

80

JOSEPH A . C U R I A L E a n d

MARTIN R. GIBLING

observations is consistent with the low Tma~ and VR values discussed earlier (Table 2). Because of the small amount of section involved here, no maturity trend is expected for this sample set.

13(17)-ene, the dominance of the 20R sterane isomer, the presence of 5fl-steranes (Fig. 12, lower panel), and the strong odd dominance of the C26_32n-alkanes (Figs 8 and 9) all attest to low maturity. Each of these

95

191

m/z 299

DAMMAR-13(17)-ENES SPL

204-21

[

I

i

50

100

412

231

150

200

250

300

350

400

450

amu

I

i

I

I

I

I

20R ~ 2O5

191

m/z 301 13p, 17~(H)-DAMMARANES

•

, •

i

95

,

\

301

1 ,414 .

~ i

I

!

I

50

~

.

J

~

100

150

200

1,l:.,1_,,_

250

j I ,.."J"

300

350

.

400

amu

i

m

TIC I

2000

2050

2100 2150 2200 SCAN NUMBER

2250

2300

Fig. 11. Mass chromatograms and mass spectra indicating the occurrence of dammaranes and dammarenes in a representative sample (204-21) of the Mac Sot oil shales. The partial m/z 299 and 301 mass chromatograms (top and middle, respectively) show the presence of two dammar-13(17)-enes and two 13fl,l 7a-dammaranes, respectively. Adjacent insets show mass spectra of one of each (for comparison with those published by Meunier-Christmann et al., 1991; stereochemistry at C-20 is tentative). The lowermost trace is part of the total ion chromatogram (TIC) of this full-scan GCMS run; peak designations correspond to those listed in Table 5. See text for further details.

.*.

450

Productivity control on oil shale formation

81

400 204-71

m

4.85M m/z 191.18

300 A

>

E ~200 z uJ l.z

t

E

P

100 i

0 42

i

44

46

L

i

I

i

i

52 48 50 TIME (IN MINUTES)

54

56

58

300 204-71

C29

250!

4.85m -7

m/z 217.20

> E 200

z

uJ 150 I-2: m

C28 C27

~

44

46

i

100

50

042

~

48 50 52 TIME (IN MINUTES)

54

• . • ,3._.

56

• •

58

Fig. 12. Typical (partial) rn/z 191.18 (top) and 217.20 (bottom) medium resolution (5000) mass chromatograms for the Mae Sot oil shales (sample 204-71 at 4.85 m). These traces show the tricyclic and pentacyclic terpanes (top) and the steranes (bottom). Peak designations correspond to those listed in Table 5.

Nevertheless, several traditional molecular maturity parameters co-vary (e.g. 22S/(22S + 22R)-30-homohopane and 17fl/17ct-22,29,30-trisnorhopane; Table 6) suggesting that reactions that alter these so-called maturity indicators can be advanced by processes other than maturity. That many of these classical maturity indicators are controlled by organic facies, lithofacies or diagenetic processes has been inferred

from data of Moldowan et al. (1986), Curiale and Odermatt (1989), Li et al. (1991), Peters et al. (1990). Curiale and Stout (1994) and several others, This is clearly the case for the Mae Sot sample set de~ribed here, because (for example) over 50% of the total possible variation in the 22S/(22S + 22R)-30-homohopane ratio is present in less than 7 m of vertical section. This remarkable variability makes question-

82

JOSEPHA. CURIALEand MARTINR. GIBLING

able the use of molecular maturity markers in immature Tertiary lacustrine settings. ORGANIC MATTER IN THE MAE SOT LAKE(S)

The linear trend in the van Krevelen diagram (Fig. 6) suggests that the richest oil shales contain the highest concentration of algal (i.e. water-column-derived) debris, whereas the grade D oil shales contain algal debris accompanied by hydrogen-poor organic matter (from oxidized amorphous kerogen? land plants?). This effect is apparent in the quantitative pyrolysis-gas chromatography (PGC) data. Figure 13 shows typical PGC chromatograms from each of the four oil shale grades at Mac Sot, each normalized to the same amount of internal standard. The most prominent change from the highest grade (A) shales to the leanest (D) shales is the decrease in hydrocarbon intensity (relative to the standard). This drop in absolute yield of n-alkanes + n-alkenes correlates directly with the decrease in hydrogen index in Fig. 6 (cf. Larter and Senftle, 1985; Powell et al., 1991; Hollander et al., 1991). Non-systematic changes in the amounts of prist-l-ene (p), xylenes (x) and toluene (t) in the section are also evident. Increased waxiness upsection (Fig. 13) occurs concurrently with an increase in hydrogen-richness, and therefore source rock potential. As noted earlier, the occurrence of waxy material in lacustrine sediments is not uncommon in oil shales (Bradley, 1970; Kelts, 1988), and its origin has been attributed, at one time or another, to bacterial biomass, water-column organisms (e.g. phytoplankton) and fluvial detritus derived from land-plants. Our data, when interpreted in light of classical concepts, are consistent with the presence of all three of these organic matter types. First, bacterial input is strongly suggested by (among other things) the presence of hopanoids and dammaranes. Second, algal bodies are inferred from the occurrence of large amounts of fluoramorphinite, isotopically light carbon, and carotenoids. Finally, land-plant contributions may be deduced from relatively high concentrations of 24-ethylcholestane (Fig. 12) and high odd/even C27 33 n-alkane ratios (Fig. 9). Accurate estimates of terrigenous organic input to the Mac Sot lake(s) are important for reconstructing the Mac Sot Basin during Pliocene/Miocene lacustrine oil shale deposition. However, notwithstanding the preceding discussion of a possible terrigenous dilution effect in our samples, all of the so-called "land-plant molecular indicators" in our data can be derived from algal and/or bacterial inputs, and therefore land-plant contributions need not be invoked. The long-chain n-alkanes (i.e. C25+ waxes) can be attributed to algal (Clark and Blumer, 1967; BenAmotz et al., 1985; and others) or bacterial (Han and Calvin, 1969; Albro, 1976) inputs, as mentioned earlier. In addition, although a high ratio of odd to even C25÷ n-alkanes is used by many workers to infer

terrigenous input, such ratios are common in algal (Gelpi et al., 1970; Cranwell, 1976) and even bacterial (Albro, 1976) hydrocarbon distributions as well. Other so-called land-plant indicators also have sources that are non-terrigenous (e.g. see the review by Volkman, 1986). CONTROLS ON HYDROGEN INDEX AND 613C,,~

The 6 ~3C values in various organic fractions of the Mac Sot oil shales vary by greater than 10%o (Fig. 7; Tables 3 and 4), and this variation may suggest organic facies fluctuation caused by changes in the bioassemblage input. In this section, we propose that the wide range of carbon isotope values in this sample set does not result from organic facies changes or significant climatic fluctuation (cf. LaZerte, 1983; Krishnamurthy et al., 1986; Talbot and Livingstone, 1989), but rather from the effects of water column productivity variation o n 613C of organic matter contributed to the sediment. The data in Tables 2-4 show a positive correlation between oil source rock potential (e.g. TOC, HI) and the 6 ~3C value of each organic fraction. The relationship between HI and (~IaCEo M is shown in Fig. 14. TOC in these lacustrine sediments is a function of both the productivity of the surface waters and the extent of preservation of the organic matter during settling and early burial. In contrast, the HI is not a direct productivity indicator, but relates to the preservation of organic matter in the water and sediment columns (cf. Hollander et al., 1991). Because sedimentological evidence (Gibling et al., 1985b) suggests that the sediment column in the Mac Sot lakes was anoxic at this location, the preservation potential of the sediments should have been invariant over time, leaving variability in preservation potential at the water column as the controlling process governing HI. Our proposal that the variation in HI in our sample set results from different preservation rates within the water column, prior to deposition, is consistent with the results of Hollander (1990) and Hollander et al. (1991). These workers showed a strong relationship between HI in Lake Greifen (Switzerland) recent sediments and the percentage of the water column that was anoxic at the time of deposition. The reasonably constant organic facies within the Mac Sot oil shales (based on organic petrographic data), along with the suggestion that HI is controlled by variation in extent of preservation of organic matter in the water column, raises interesting questions about the cause of the organic carbon isotopic variability. In general, 6 ~3Corg may be a function of numerous factors, including changes in bioassemblage (particularly variations in bacterial input), diagenetic reactions (both organic and inorganic) and gradients within the water column (particularly the photic zone). However, if organic facies reflects organic matter type input, then the input type should

Productivity

control

o n oil s h a l e

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84

JOSEPH A. CURIALE and MARTIN R. GIBLING

have been reasonably constant. If HI is a function of the extent of preservation of organic matter in the water column, then the observed isotopic variability of 5%o can be (a) due to isotopic "fractionation" during transport to the lakewater-sediment interface, or (b) a direct reflection of isotopic variability associated with biosynthesis of organic matter in surface waters. In order for the first possibility to apply, isotopic variation within compound classes of a single sample (e.g. aliphatic hydrocarbons through asphaltenes) must be at least 5%o. However, data in Fig. 7 show that the intra-sample variation is quite minor (2%o), and we therefore exclude possibility (a). We propose that the Mac Sot oil shale organic carbon isotopic variability directly reflects variability in surface waters, and that both are due to temporal variation in productivity (Stuiver, 1975; McKenzie, 1982, 1985; Hollander, 1990; Hollander et al., 1991, 1992; Hollander and McKenzie, 1991). In the Mae Sot lake environment, the isotopic signature of the organic matter in the oil shales was inherited directly from surface-water organic matter and/or watercolumn bacteria (perhaps associated with the chemocline), and is thus a function of the stable carbon isotope ratios of the inorganic carbon source in the water column (initially CO 2 and subsequently perhaps HCO3). Productivity blooms, instigated by increasing nutrient influx, scavenged CO2 from the upper part of the water column (cf. Deuser, 1970). This led to reduced pCO2, and depleted the remaining CO 2 in ~:C (McKenzie, 1985). Continued productivity increases led to burial of organic carbon that was progressively more depleted in ]2C, yielding

a positive correlation between productivity and 6 ]3C of the preserved organic matter (Aravena et al., 1992). This model is shown in cartoon form in Fig. 15. Potential support for the effect of CO2-1imiting conditions on the carbon isotope ratio of the organic matter could be provided by examination of the 6 ~3C values of carbonate in the Mae Sot oil shales. However, this is only true if the carbonates now in these shales are unchanged from the time of their production in the surface waters, rather than being the product of diagenetic reactions following deposition. Gibling et al. (1985b) noted that direct precipitation of carbonates was probable in Mae Sot Lake(s). However, dolomite is present in greater amounts than calcite in much of the oil shales sequence, and is considered to have formed during early diagenesis (Gibling et al., 1985b). This is supported further by indications that Fe-enriched dolomite is present in several samples (Gibling et al., 1985b). In addition, Gibling and Kelts (1981, unpublished results) suggested that both calcite and dolomite in the oil shales are diagenetic, based upon carbon and oxygen isotope analyses. Our carbon isotope results for total carbonate in the Mae Sot sample set (Table 3) appear to concur, inasmuch as no obvious relationship is present between 613Ccarb and either 613Cker (Table 3) or 313CEoM (or compound classes within the EOM; Table 4). Furthermore, the presence of significant amounts of secondary carbonates in the Mae Sot oil shale sample set precludes the application of parameters such as A3 ~3C(carb_org) for confirming CO2-1imiting conditions, as used by Hollander et al. (1992) in

1,200

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1,100 L 1,000

x

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-29

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Productivity control on oil shale formation

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85

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Fig. 15. Suggested model depicting the origin of the hydrogen index-6~3CEoMcorrelation in the Mac Sot oil shales (Fig. 14). Two productivity level extremes during the life of Mac Sot Lake(s) are shown. The percentage of the water column that is anoxic is a function of surface water productivity; both decrease from left to right. Decreasing productivity results in movement down the HI-6 ~3CoMcurve. This model assumes that the extent of organic matter preservation within the sediment column is high (and constant), based upon sedimentological evidence (Gibling et al., 1985b). the comparatively recent sediments of Lake Greifen, that isotopic source variability of greater than 5%oo Switzerland. Based upon these considerations, we can occur in less than 7 m of section (Fig. 7). Thus it conclude that carbonate isotope data for our sample should be assumed that fi 13C of oils generated from set can neither support nor refute the general con- such a sequence may reflect a composite of a section clusion that increased productivity has led to enrich- with wide-ranging &~3C values. ment of ~3C in the dissolved carbon pool of the surface waters, causing a covariance between fia3Corg DEPOSIT1ONAL SE'VI'ING INFERENCES and HI. Our reasoning leads to the conclusion that HI is Based upon the molecular, isotopic and organic controlled by water-column preservation, whereas petrographic data discussed earlier, the organic mat613C is a function of surface-water productivity ter in our Mac Sot samples is considered to constitute (Fig. 14). However, if our inferences about con- a single class of organic facies. In this section we trolling processes are correct, we note that (given discuss the water column and sediment characteristics deposition below a chemocline), productivity and necessary to create and preserve organic matter in preservation increase simultaneously. In these cir- this facies. However, the lithofacies bias in our data cumstances, increased productivity appears to lead to set must first be recognized: our study includes only enhanced preservation, each reflected (respectively) in oil shales from one exposed flank of the Mac Sot the hydrogen index and the carbon isotope ratio Basin, and we have not examined the marlstones/ (McKenzie, 1985; Hatch et al., 1987; Hollander, sandstones intercalated with the oil shales (Gibling 1990; Hollander and Hayes, 1991; Hollander et al., et al., 1985b). 1992; Ludrigson et al., 1992; Pradier and Bertrand, The variation in amount and distribution of or1992; Calvert et al., 1992). This unusual situation ganic matter in lacustrine shales reflects fluctuations would occur only if, as in the case of the recent in physical characteristics of the lake system. These history of Lake Greifen, Mac Sot lake was "unable characteristics include climate, water column salinity, to maintain CO 2 equilibrium with the atmosphere surface relief and the extent and type of vegetation in during times of extreme productivity" (Hollander the surrounding highlands (Kelts, 1988). In the case and McKenzie, 1991, p. 930). of the grade A Mac Sot shales, it is clear from The proposed relationship between productivity geochemical and sedimentological evidence that the and f~3C of the preserved organic matter raises a water column "must be density-stratified and hydroquestion about the use of carbon isotope data as dynamically stagnant on the bottom" (Jones, 1987, oil-source rock correlation tools in lacustrine oil-gen- p. 36; see also Gibling et al., 1985b). Density stratifierative basins. In particular, previous work cation probably resulted from formation of a halosuggesting a < 2%o difference between oils and their cline, an inference supported empirically by the marine source rock kerogens (e.g. Seifert et al., 1979) presence of perhydro-/3-carotene (among other caromay not have application to lacustrine systems in tenoids) in the rocks (Murphy et al., 1967; Schwab situations where lakewaters become CO2-1imited and and Schlobach, 1973; Hall and Douglas, 1983; see where source rock sampling is at coarse resolution Fig. 8). (e.g. 10 m). Isotopic efforts to correlate oils to their As discussed above, the variation in source rock lacustrine source rocks must take into consideration potential over this 7 m section, indicated by the

86

JOSEPHA. CURIALEand MARTINR. GIBLING

hydrogen index and other parameters discussed earlier, can be attributed to variability in the extent of organic matter preservation in the water column. An overall model of deposition contains several sequential elements. Nutrient influx from the surrounding highlands, accompanied by minor amounts of terrigenous organic matter, causes productivity blooms. The resultant biota contain carbon progressively enriched in ~3C. Increased biomass moving to the watersediment interface yields a water column depleted in molecular oxgyen, generating sub-oxic or anoxic conditions. The resulting enhanced preservation allows the total organic carbon and hydrogen index values in the sediments to remain near their original high values. In effect, periods of high productivity (with high 613Corg and high hydrogen index) are interrupted by periods of lower productivity (with low fi 13C and hydrogen index) (Fig. 15). Throughout this scenario, anoxic conditions spread to much or all of the water column, which remains oxygen-free due to the presence of permanent density stratification caused by minimal turnover (in this tropical climate; Katz, 1990) and insufficient high-energy environmental factors (such as deltaic developments and accompanying downslope mass flows) at the lake margins. In lieu of specific data concerning phytoplankton and bacterial assemblages during Mae Sot time, this model provides an explanation for the observed relationship between hydrogen indices and carbon isotope ratios of the organic matter. It is often stated that the formation of high concentrations of organic matter in sedimentary rocks requires exceptional conditions for preservation that include anoxic bottom waters (Demaison and Moore, 1980). However, considerable data from the oceanographic literature imply productivity as a primary cause of organic matter accumulation (Calvert, 1987; Calvert et al., 1991, 1992, and references therein; Cowie and Hedges, 1992). Our results and interpretation support productivity as the primary precursor to the creation of organic-rich sediments. Enhanced production of hydrogen-rich organic matter in surface waters of the Mac Sot Lake(s) has forced a higher percentage of the water column toward anoxic conditions. Thus productivity controls, indirectly, (a) the amount of organic detritus reaching the sediment-water interface (as a percentage of organic matter leaving the photic zone), and (b) the resultant concentration of organic carbon in the sediment column. As surface productivity increases, oxidative loss of hydrogen-rich organic matter in the water column decreases, yielding sediments of increasing organic richness. These productivity increases are reflected in both 6 J3Cor, ratios (directly) and hydrogen indices (indirectly). CONCLUSIONS

Because thermal maturation and fluid migration are considered invariant in our sample set, molecular

and isotopic changes within the Mae Sot shales are a function of depositional and preservational processes only. Based on organic petrographic (fluoramorphinite) and specific molecular similarities (tricyclic terpanes; perhydro-/%carotene) throughout the 7 m section, we conclude that original organic matter input to the water-sediment interface was similar through time. Consequently, those geochemical parameters that vary throughout the samples set (TOC, HI, 6~3C, relative n-alkane content in pyrolyzates) are controlled by differences in surface-water productivity and water-column/sediment-column preservation over time. Our major observations and conclusions are as follows. 1. The Mac Sot oil shales are potential oil source rocks containing Types I and II organic matter, as defined using a modified van Krevelen plot. 2. The organic matter in all samples, when examined as kerogen concentrates, consists predominantly of fluoramorphinite. However, this unstructured material probably results from lamalginite that has lost its characteristic morphology due to acid maceration (Sherwood et al., 1984). 3. The sample set is thermally immature. Nevertheless, molecular "maturity" parameters range widely and correlate internally. Furthermore, over half of the total theoretical variation in certain maturity parameters is present over only 7 m of section. 4. Pristane/phytane ratios are less than unity, and numerous diagnostic molecular markers are present. These include specific tricyclic terpanes present in novel distributions, perhydro-B-carotene, norsterane (s) and dammaroids. Although evidence is present to suggest some terrigenous input, our entire data set (including high molecular weight n-alkanes and an odd carbon n-alkane predominance) can be explained without invoking such input. 5. Organic carbon isotope ratios (613C) co-vary with hydrogen indices. We propose that this relationship results from variation in surface-water productivity in a CO:limited photic zone. Whereas isotope ratio changes are due to depletion over time of t2C in the surface waters, and are thus a direct result of productivity fluctuation, hydrogen indices vary according to the percentage of the water column that is anoxic. Thus increased productivity is considered a precursor for changes in hydrogen index, inasmuch as a significant control on HI is the preservation of organic matter as it passes through the water column, which in turn is a function of anoxia created by increased productivity (Fig. 15). Our results show that carbon isotope ratios in lacustrine source rocks can vary as a function of surface productivity, and that caution must be exercised in the use of 6~3C to correlate oils to their suspected lacustrine sources. Finally, it is also noted that existing definitions of organic facies rely heavily on both hydrogen index determinations (Jones, 1987) and visual kerogen analysis. Our results and those of

Productivity control on oil shale formation others (e.g. Hollander, 1991) suggest that H I in the sediment c o l u m n m a y not reflect fluctuation in organic m a t t e r type or maturity. Rather, in algal-rich high-productivity e n v i r o n m e n t s where C O s is being removed from surface waters at very high rates, H I variation may reflect differences in preservation rate d u r i n g passage t h r o u g h the water column. Associate E d i t o r - - M . RADKE Acknowledgements--This work is part of a multi-year project to investigate the oil source rock potential of Tertiary lacustrine sediments, and we extend our appreciation to Unocal management for supporting this research effort and encouraging publication. The authors benefited from discussions with R. I. Haddad, B. W. Bromley, R. E. Sweeney, A. H. Sailer and S. A. Stout. Sample preparation, extraction and fractionation were handled by C. A. Tucker and M. J. Hartley. Z. A. Wilk and C. R. Snelling assisted with collection and processing of the GCMS data; discussions with Z. A. Wilk on the uses and abuses of metastable ion data are appreciated. Samples were collected during a project funded by the Electricity Generating Authority of Thailand (EGAT), and the second author gratefully acknowledges assistance from many former colleagues and students as Chiang Mai University, from EGAT geoscientists, and from the residents of Ban Huai Kalok. Financial assistance with manuscript production was provided by a Natural Sciences and Engineering Research Council of Canada Operating Grant to M.R.G. We appreciate reviews of an early version of the manuscript by M. Schoell, B. Luo and M. A. Smith, and in particular excellent reviews by K. E. Peters and D. J. Hollander. REFERENCES

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