Geochemical characterization of lithofacies and organic facies in Cretaceous organic-rich rocks from Trinidad, East Venezuela Basin

Pergamon 0146-6380(94)00088-3

Advances in Organic Geochemistry 1993 Org. Geochera. Vol. 22, No. 3-5, pp. 441-459, 1994 Elsevier Science Ltd. Printed in Great Britain 0146-6380/94 $7.00 + 0.00

Geochemical characterization of lithofacies and organic facies in Cretaceous organic-rich rocks from Trinidad, East Venezuela Basin* A. G. REQUEJO, 1'2 C. C. WIELCHOWSKY, 3 M. J. KLOSTERMAN3 and R. SASSEN2 tExxon Production Research Company, P.O. Box 2189, Houston, TX 77252, 2Texas A&M University, Geochemical and Environmental Research Group, 833 Graham Road, College Station, TX 77845 and 3Exxon Exploration Company, P.O. Box 4279, Houston, TX 77210, U.S.A. Abstract---Organic-rich Cretaceous sediments from southern Trinidad show differences in hydrocarbon source potential which can be geochemically related to lithofacies and organic facies. Sediments which exhibit good to excellent potential for oil were deposited during the Campanian through Cenomanian in clastic-starved environments, as evidenced by the inverse relationship between Hydrogen Index and the parameters AI203/TOC and Th/U. Principal Components Analysis (PCA) of combined TOC, Rock-Eval, major oxide and trace element data shows three lithofacies---carbonate, siliceous and clastic--within samples exhibiting hydrocarbon source potential. The highest petroleum potential is associated with the siliceous and carbonate lithofacies, which consist of hemi-pelagicsediments deposited under low oxygen conditions. The clastic lithofacies have lower petroleum potential and represent nearshore sedimentswhich have been transported to the continental slope via submarine canyons. Extractable saturated and aromatic hydrocarbon compositions vary with lithology. PCA of conventional biomarker and 2- and 3-ring aromatic hydrocarbon distributions shows that the carbonate lithofacies are characterized by an enrichment in ctfl/~steranes and dibenzothiophenes. Two organic facies can be recognized within the carbonate lithofacies that differ in their relative abundance of tricyclic terpanes, gammacerane and bisnorhopane. The siliceous lithofacies are characterized by an abundance of bisnorhopane, ~tct~t(20R) steranes and a slight enrichment in naphthalenes relative to phenanthrenes. The clastic lithofacies exhibit high hopane contents relative to steranes, an enrichment in moretanes and 18ct(H)-oleanane, and an enrichment in phenanthrenes relative to naphthalenes.

Key words--petroleum, source rocks, organic facies, biomarkers, aromatic hydrocarbons, major oxides, thorium/uranium, Trinidad, multivariate analysis

INTRODUCTION

The island of Trinidad is a prolific, mature oil province located in the northeastern portion of the East Venezuela Basin (Fig. 1). Trinidad can be subdivided into several tectonostratigraphic provinces that formed at different stages of structural development. Most important in terms of hydrocarbon production are the Southern Basin and the Columbus Basin (Fig. 1). Deep water marine shales and mudstones of Cretaceous to Miocene age are overlain by younger deltaic sediments that contain the major hydrocarbon reserves in Trinidad. Approximately 2.5 billion barrels of oil and 20 trillion cubic feet of gas have been produced from both offshore and onshore fields. The principal reservoirs are of Plio-Pleistocene and Miocene age (Fig. 2) and were formed in association with a Late Miocene transpressional tectonic phase. Hydrocarbon traps usually have both stratigraphic and structural components. Previous geochemical studies concluded that organic-rich shales of the Upper Cretaceous Naparima *To avoid further delay in publication of this issue, this paper has been published without the authors' corrections.

Hill and Gautier Formations (Fig. 2) are the source of Trinidadian oils. These units represent deep-water deposition of hemi-pelagic sediments, turbidites and submarine fan sediments on a passive margin continental shelf and slope under anoxic or dysoxic conditions. The Naparima Hill Formation has total organic carbon (TOC) concentrations up to 8.0%, Hydrogen Indices (HI) up to 640 mg/g, and contains primarily unstructured, oil-prone, Type II kerogen (Rodrigues, 1988; DGSI, 1988). Rich petroleum source rocks age equivalent to the Naparima Hill occur elsewhere along the northern margin of South America, most notably the San Antonio, Querecal and La Luna Formations of Venezuela (Talukdar et al., 1986; 1988). The underlying Gautier Formation also contains organic-rich shales, with TOC concentrations up to 7.5% (Rodrigues, 1988). However, the source quality of this unit varies regionally, and may be characterized as either oil-prone or gas-prone. Where lean, the Gautier can also contain significant thicknesses of sandstone. Heavy oil (18 o API gravity) has been recovered from Gautier sands in southcentral Trinidad. Maturity assessments of the Naparima Hill and Gautier Formations indicate immature to mature occurrences throughout onshore and offshore Trinidad based primarily on TAI, vitrinite

441

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Fig. 1. Map of Trinidad showing the major tectonostratigraphic provinces and the locations of wells included in this study.

reflectance and limited Rock-Eval data (Rodrigues, 1988; DGSI, 1988). Other Cretaceous strata in Trinidad exhibit limited liquid hydrocarbon potential. Rodrigues (1988) reported low to moderate TOC and HI for samples from the Guayaguayare Formation (Fig. 2). The same study found that the lower Cretaceous Cuche Formation has TOC concentrations up to 30% but consists largely of woody, coaly and herbaceous organic matter with limited oil potential. Tertiary shales are largely organic-lean and are similarly dominated by terrestrial kerogen (Leonard, 1983; Robertson Research, 1983; Rodrigues, 1988). This study more closely examines the hydrocarbon geochemistry of Cretaceous source rocks throughout Trinidad. Samples covering the entire Cretaceous section have been analyzed by conventional screening methods to better define vertical and lateral variations in source potential. These results have been interpreted in the context of chemical lithofacies. This term describes a quantitative approach to lithologic description based on concentrations of the major oxides and trace elements comprising the mineral matrix. In this study, the distributions of major oxides and trace elements have been related to hydrocarbon source potential using Principal Components Analysis (PCA). Extractable saturated and aromatic hydrocarbon compositions were also analyzed by PCA in order to characterize the organic facies corresponding to each lithofacies. PCA has received widespread application in the analysis of geochemical data, including organic facies assessment (e.g.,

Oygard et al., 1984; Teln~es and Dahl, 1986; Melio et al., 1988; Irwin and Meyer, 1990; Eglinton et al., 1992). Nearly 400 source rock samples have been analyzed, making this one of the most comprehensive geochemical evaluations of the Trinidadian hydrocarbon system.

EXPERIMENTAL Samples A total of 377 samples of conventional core were collected from eight wells that penetrated the Cretaceous: Moruga East-15 (ME-15), Antilles Brighton102 (AB-102), Esmerelda-I (ES-1), Mount Harris-I (MH-1), Moruga West-45 (MW-45), Morne Diablo34 (MD-34), Marac-1. (MR-I) and Guayaguayare163 (GY-163). The well locations are shown in Fig. 1. The majority of these wells were drilled during the 1950s and 1960s and hence well logs were not of sufficient resolution to closely relate sampled interval to log response. The sampling was biased to exclude sands and silts and focused primarily on shale and carbonate intervals. Table 1 summarizes the intervals sampled within each well. Analytical methods All core samples were analyzed for total organic carbon (TOC) content. Those containing in excess of 0.5 weight percent TOC were analyzed by Rock-Eval pyrolysis. Based on these results, 49 samples were selected for kerogen isolation and subsequent microscopy to determine the distribution of organic matter

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Fig. 2. Stratigraphy of Trinidad.

Chronostratigraphic Summary Trinidad

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Hydrocarbon geochemistry of Cretaceous source rocks, Trinidad Table 2. Rock-Eval T-max, vitrinite reflectance (Ro) and selected inorganic parameters for Cretaceous chronostratigraphicintervalsexaminedin this study Maturity Pammetem

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430-435

0.48

8.48

15.60

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1.62

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4.55

types, TAI and vitrinite reflectance. These analyses were performed by DGSI (The Woodlands, TX). A subset of 233 core samples were analyzed by X-ray fluorescence (XRF) spectrometry to determine the major and minor oxides and trace elements comprising the mineral matrix. These data are useful in quantifying variations in lithology. Total sulfur and selected trace elements were also determined by XRF. Acid-evolved CO 2 was determined by titration followed by coulometric determination. These analyses were performed by X-ray Assay Labs (Ontario, Canada). A subset of 23 samples were selected for semi-quantitative X-ray diffraction (XRD) analysis to calibrate the X R F results. This analysis yields bulk mineralogy as well as composition and species of the clay fraction. These analyses were performed by Core Laboratories (Houston, TX). A subset of 27 samples were selected for detailed molecular characterization. Samples were solvent-extracted and separated using liquid chromatography

.

8.14

.

2.92

4.11

4.78

into C~5+ saturated hydrocarbon, aromatic hydrocarbon, heterocompound and asphaltene fractions. The saturated and aromatic hydrocarbon fractions were analyzed by gas chromatography, gas chromatography/mass spectrometry and isotope mass spectrometry. Concentrations of triterpanes, steranes, naphthalenes (di- and trimethyl isomers), phenanthrenes (through dimethyl isomers) and dibenzothiophenes (through methyl isomers) were calculated using surrogate standards. Analytical conditions have been described in Requejo et al. (1992) and Requejo (1994). Multivariate analysis The organic and inorganic data were analyzed using PCA (Joliffe, 1986). The results obtained using PCA are highly dependent on the pre-treatment or scaling of the data matrix. The combined TOC, Rock-Eval and oxide data were analyzed following scaling by dividing each variable by its standard

A. G. REQUEJOet al.

446

the significance of each principal component. PCA was performed on a personal computer using the program SIRIUS (Pattern Recognition Systems, Bergen, Norway).

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RESULTS AND DISCUSSION

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In the following discussion, we adopt a stratigraphic nomenclature whereby the various Cretaceous strata are identified according to their interpreted chronostratigraphic units. Thus, the Maestrichtian corresponds roughly to the Guayaguayare Formation, the Upper Campanian through Turonian to the Naparima Hill Formation, the lower Cenomanian through the Upper Albian to the Gautier Formation and the Albian/Aptian through the Barremian to the Cuche Formation. Table l shows the approximate chronostratigraphic interval corresponding to each formation.

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Hydrocarbon source potential

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Average TOC concentrations and Rock-Eval HI for chronostratigraphic intervals penetrated in each well are summarized in Table 1. Organic-rich sediments which exhibit good to excellent potential for oil were deposited primarily during the Campanian through Cenomanian. Average organic carbon contents range from 1.9 to 7.9% TOC while average HI range from l l4 to 596mg/g. These sediments are encountered in the ES-1, GY-163, MR-I, MW-45 and ME-15 wells. Sediments of Maestrichtian age with good source potential for oil are found in the AB-102 well. TOC concentrations in this well range 2.5-2.9%, with average HI ranging 402--412mg/g. Most other Maestrichtian-age sediments analyzed can be classified as either poor oil/good gas sources

•

t i

Fig. 3. Graph showing effect of solvent extraction on Rock-Eval Tmax. (---) represents conventional threshold of hydrocarbon generation (Peters, 1986). deviation. This assigns every variable a variance of 1.0 so that each one has the same influence in the PCA model. The extractable hydrocarbon data was transformed by block log normalization of the saturate and aromatic hydrocarbons. The technique of cross-validation (Wold, 1978) was used to establish

14

Data from 7 wells Only immature/e~rty mature intervals shown

Ma•htlan

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•

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100

200

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300 400 Average Hydrogen Index

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Fig. 4. Plot of average AI203/TOC versus Hydrogen Index for different Cretaceous chronostratigraphic intervals.

Hydrocarbon geochemistry of Cretaceous source rocks, Trinidad

447

Maest~hkn

Data from 7 wells Only immature/early mature intervals show~ 6

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Average Hydrogen Index Fig. 5. Plot of average Th/U v e r s u s Hydrogen Index for different Cretaceous chronostratigraphic intervals. or poor gas sources. Average organic carbon concentrations and HI of these sediments range 0.5-1.8% and 20-247 mg/g, respectively. Sediments of Albian age in general contain intermediate organic carbon concentrations and Rock-

Eval HI. Average values range 1.6-1.9% and 141-171 mg/g, respectively. These sediments are encountered primarily in the MR-I, MD-34, ME-15 and MW-45 wells and can be classified as fair to poor oil and gas sources. Sediments of Albian/Aptian and

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PC 1 (32.9%) Fig. 6. Scores crossplot of PC 1 v e r s u s PC 2 obtained from PCA of TOC, Rock-Eval, major oxide and trace element data, showing the variation in lithofacies within the Cretaceous sediments analyzed. Values in parentheses represent fraction of total variance accounted for by each principal component. Filled squares denote samples selected for extractable hydrocarbon characterization.

448

A.G. Ra~QU~O et al. 0.4

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M a t u r i t y level LOI

Maturation level was assessed using conventional microscopy and Rock-Eval techniques. Where possY ible these maturity assessments were corroborated s~T~u cr NbPI using the molecular characteristics of extractable 0 0,I Ol Ba hydrocarbons. Many of the samples analyzed by 0 HI $I o.. microscopy, in particular those which exhibit good to -0.2 -excellent oil potential, contain little vitrinite. In these cases vitrinite reflectance measurements are unreli-0.4 -SK~ I I I I I able and thermal maturity level was determined from -0.3 -0.2 4.1 0 0.1 0.2 0.3 Rock-Eval Tmax (Peters, 1986). Ranges for RockEvai Tmax and measured vitrinite reflectance are PC 1 listed in Table 2. Fig. 7. Loadings crossplot of PC 1 versus PC 2 obtained The results indicate that, with exception of the from PCA of TOC, Rock-Eval, major oxide and trace Albian/Aptian section in ES-I and the Albian and element data. These loadings correspond to the scores Barremian section in MH-1 the sediments analyzed shown in Fig. 6. can be largely classified as immature to early mature with respect to hydrocarbon generation. The highest Barremian ages are largely non-hydrocarbon sources vitrinite reflectance values are between 0.55 and 0.6% (Table 1). This is in part due to their elevated level of in the MD-34 (13275') and MR-1 (11292') wells, maturity (discussed below). The organic matter con- which corresponds roughly to the onset of hydrotains a high proportion of higher plant organic carbon generation. Rock-Eval Tmax, generally in the matter; hence, at lower maturities, these sediments 425-435 ° range, are in agreement with this assesswould have source potential primarily for gas. ment. These results suggest that the effective source 0.2 ~

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i

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Fig. 8. Profile of Hydrogen Index, AI203/TOC, Th/U and PC I scores in the U. Albian through Campanian interval of the MR-I well.

Hydrocarbon geochemistry of Cretaceous source rocks, Trinidad rocks that have generated the bulk of oil in Trinidad were not sampled in the study and are likely buried at greater depth. Vitrinite reflectance values in the Albian/Aptian section of the ES-I well range 0.73-1.12%, indicating that the section is mature to overmature with respect to hydrocarbon generation, In MH-1 reflectance values are 1.93-2.18% indicating

overmaturity with respect to hydrocarbon generation. These units will not be discussed further in this paper. In most cases, the molecular characteristics of extractable hydrocarbons corroborate the maturation level inferred from either vitrinite reflectance or Tmax. However, some samples have high extractable

A. Calcareous

15

20

L Pr

B. Siliceous

Ph

_J_ 1

~

C. Clastic

Pr

15

449

25

Fig. 9. Gas chromatograms of saturated hydrocarbons isolated from representative samples of the three lithofacies identified. Numbers over the peaks refer to n-alkane carbon numbers; Pr and Ph identify pristane and phytane, respectively.

450

A.G. REQUEJOet al.

27a1~13~ 8 ~ 2 9 a ~ , [ ~

21

A. Calcareous

22

27aaa

28(

za 29aaa

B. Siliceous

i i i

21 22

51~

30aaa

i~ J|l~

29dia

C Clastic

27dia

21

Fig. 10. Mass chromatograms of m/z 217 showing sterane distributions in the three lithofacies identified. Labels over peaks denote carbon number and stereochemistry of individual isomers; 5fl identifies the added 5fl-cholane surrogate standard.

hydrocarbon yields relative to their organic carbon contents. These high bitumen contents suggest staining, which might depress Rock-Eval Tmax values and result in an underestimate of maturity level. To assess this possible artifact, Tmax of individual samples were compared before and after solventextraction. The results, shown in Fig. 3, indicate that this effect is negligible. In many cases, Tmax is

actually lower after solvent-extraction, an effect opposite that expected. Still, the difference in most cases is < 5°C, which does not significantly affect the maturation assessment. The vertical dashed line in Fig. 3 corresponds to the Tmax threshold for hydrocarbon generation (Peters, 1986) and illustrates how most of the samples analyzed have not yet entered the main phase of hydrocarbon generation. Rock-Eval

Hydrocarbon geochemistry of Cretaceous source rocks, Trinidad Tmax are also consistent with the fact that many of the samples exhibit elevated HI, which are characteristic of pre-generative, oil-prone source rocks. An unusual aspect of the Tmax data is the absence of a significant increase in inferred maturity level with depth for many of the Cretaceous intervals classified as immature to early mature, despite significant sediment thicknesses (often in excess of 4000'). The Lower Campanian to Upper Albian interval in MR-1 is one of the few in which any maturation gradient is evident. This most likely results from the relatively low geothermal gradients in the region, which are estimated to be between 1 and 1.5°F/100 ft (Rodrigues, 1986).

Lithofacies

Analysis of major oxides and trace elements in the whole rock was used to quantify variations in lithology. The results indicate that the Campanian through Turonian intervals exhibiting the greatest petroleum potential were deposited in clastic-starved environments. This is illustrated in Fig. 4, which shows a plot of average AI 203/TOC, an indirect measure of aluminosilicate clay content, v e r s u s average HI for immature to early mature chronostratigraphic intervals from seven wells. In general, intervals exhibiting the best potential for oil (HI greater than approx. 400 mg/g) have A1203/TOC ratios less than 4.0 (Fig. 4), indicating a low clastic content. The clay content of a representative subset of these sediments determined by XRD ranges from 6 to 69% , with the AI203/TOC threshold of 4.0 corresponding to a clay content of approx. 15%. Note that both the parameters used in Fig. 4 contain TOC in the denominator; hence a crossplot of A1203 versus genetic potential ($2) would yield the same distribution of data points. Sediments with the highest petroleum potential also exhibit low Fe/S ratios (Table 2), indicating a paucity of iron associated with detrital clays (Davis et al., 1988). With few exceptions, Fe/S ratios for intervals with average HI greater than 400 mg/g are less than 1.5. However, in nearly every case the Fe/S ratios are higher than the value of 0.87 associated with stoichiometric pyrite. This suggests limited amounts of "excess" iron associated with a minor clastic component, which is in agreement with the low clay content indicated by the XRD results. The paucity of iron in oil prone source rocks has implications regarding the character of petroleum generated. In clastic marine environments iron commonly reacts with reduced sulfur to form pyrite. When iron is limiting, the sulfur becomes available to react with organic matter to form sulfur-enriched Type IIS kerogens which in turn will generate sulfur-rich oils (Gransch and Posthuma, 1974). Although it is unlikely that the oil-prone kerogens examined here would be rigorously classified as Type IIS, it is probable that at low maturity they would generate 0(3 22'3-5--H

451

petroleum containing moderate to high sulfur contents. Th/U ratios vary between continental and marine deposits (Adams and Weaver, 1958) and have been empirically correlated with anoxic depositional environments (Zelt, 1985). Figure 5 shows that Th/U in the Trinidadian samples is highly correlated with source potential. Intervals with average HI greater than 400 mg/g possess average Th/U ratios less than approx. 2.0 (Table 2). Values in this range and below are generally associated with a paucity of continental material and/or sedimentary anoxia (Zelt, 1985), both of which are consistent with the other geochemical data suggesting a low clastic component and preservation of hydrogen-rich organic matter in these samples. Principal Components Analysis was used to better define the interrelationship between lithofacies and source potential. A scores crossplot of PC 1 v e r s u s PC 2 (Fig. 6) suggests three distinct lithofacies represented within samples showing significant hydrocarbon potential. The loadings crossplot in Fig. 7 can be used to evaluate the geochemical characteristics corresponding to each lithofacies. Several variables indicative of carbonate content cluster in the upper left hand portion of the loadings plot: % CO 3, CaCO3, CaO and CO2(CaCO3 was calculated from the CaO content assuming 100% of the calcium occurs as calcite. The % CO3 parameter is the difference between total carbon and TOC determined by high temperature combustion). These variables are loaded negatively in PC 1 and positively in PC 2. Other variables that covary with carbonate content include TOC and Rock-Eval $2 as well as uranium, apatite and strontium concentrations. Thus, samples with negative scores for PC 1 and positive scores for PC 2 define a carbonate/ phosphatic lithofacies with good petroleum source potential (Fig. 6). Figure 7 also shows the covariance of the oxides A1203, K20, Na20 and TiO2 and the trace elements Zr, Rb and Th. These variables, which are positively loaded in both PC 1 and PC 2, are characteristic of aluminosilicate clays and define a clastic lithofacies. Samples with positive scores for PC 1 and PC 2 are therefore enriched in clastics (Fig. 6). Samples with positive scores for PC 1 and negative scores for PC 2 are also clastic-rich but have a greater siliceous component, most likely quartz. This is indicated by the strong negative loading for SiO 2 in PC 2 (discussed below). Since these samples are inversely loaded with organic indicators of source potential such as TOC and $2, this lithofacies has only fair or poor petroleum potential. Note in Fig. 7 that A1203 and Th, variables that serve as numerators in the ratios discussed earlier, are loaded inversely with TOC and U in PC 1, which are used in the denominators. PC 1 thus reflects the relative abundance of carbonate and clastic components and covaries with these ratios.

452

A. G. REQUEJOet al.

A third lithofacies consisting of samples relatively enriched in silica that also exhibit good petroleum potential can be recognized. The loadings plot in Fig. 7 shows that SiO2 is loaded inversely with most other measured variables in PC 2. Thus, samples showing negative scores for both PC 1 and PC 2 in Fig. 6 are characterized by an enrichment in organic indicators such as TOC and $2 as well as SIO2, most likely a biogenic form such as a diatomite or chert. In this regard, it is noteworthy that HI is also loaded slightly negatively in PC 2. This suggests that the siliceous lithofacies may not be as enriched in TOC as the carbonate lithofacies, but the organic matter preserved is somewhat more hydrogen-rich. These lithofacies can be described in the context of depositional environment. The Upper Cretaceous of Trinidad was deposited in relatively deep water on a passive margin continental shelf and slope that was incised by submarine canyons. In this setting, the siliceous and carbonate lithofacies represent organicrich, hemi-pelagic sediments deposited under lowoxygen conditions that would favor source rock formation. The clastic facies are nearshore and continental shelf sediments which were transported to the continental slope along submarine canyons either through slumping, debris flows or turbidity current flows. Regional variations in source quality would be determined in part by the distribution, size and lateral extent of these sediment transport features. Zelt (1985) in a study of Greenhorn Formation outcrop sections from the Cretaceous seaway of North America related a decrease in Th/U to increasing distance from shore. In the Cretaceous of Trinidad, it appears Th/U is less a function of distance from shore than of the transport of clastic material to the continental slope and rise. Similar lithofacies variations can be observed stratigraphically. Figure 8 shows profiles of HI, A1203/TOC and Th/U for the Upper Albian through Campanian section in the MR-1 well in south-central Trinidad (number 4 in Fig. 1). At the transition from the Gautier to the Naparima Hill Formations there is an abrupt lithologic change from clastic-rich shales and sandstones to siliceous mudstones and marls. This is accompanied by a sharp increase in HI and a decrease in both AI203/TOC and Th/U (Fig. 8). It is interesting to note that this increase occurs during U. Cenomanian-Turonian time. Kunht et al. (1990) observed that pre-Cenomanian sediments throughout the western Mediterranean and the adjacent Atlantic margin were characterized by a high terrestrial component. Curiale (1994) noted a decrease in Th/U similar to that reported here at the Cenomanian-Turonian boundary in the Bridge Creek section of the Greenhorn Formation at Red Wash, New Mexico, which he attributed to increasing distance from paleoshoreline. It may be that the coincident timing of these iithologic changes reflect a change in sedimentation patterns associated with global

Oceanic Anoxic Events during the Cretaceous (Schlanger et al., 1987). Also shown in Fig. 8 is a profile of the scores for PC 1, which parallel the trends observed in the A12OflTOC and Th/U ratios over the same interval. This illustrates how PC 1 varies directly with clastic content and inversely with source potential in these sediments. Organic facies

Compositions of extractable saturated and aromatic hydrocarbons were determined for 27 samples representing the three lithofacies (samples identified by solid squares in Fig. 6). Significant differences in hydrocarbon composition are evident for each lithology. This is illustrated by saturated hydrocarbon and sterane distributions shown in Figs 9 and 10, respectively. Saturated hydrocarbons within the carbonate lithofacies [Fig. 9(A)] are characterized by an abundance of paraffins in the range C13 to C25+ and pristane/phytane less than 1.0. These attributes are typical of many carbonate source rocks (Palacas et al., 1984; Zumberge, 1984; Sassen, 1990). One unusual aspect is the high n-alkane/isoprenoid ratios evident in Fig. 9(A) for a source rock at the threshold of hydrocarbon generation. It is possible that conventional criteria for variations in this ratio with maturity (Tissot et al., 1971; Connan and Cassou, 1980; Requejo, 1994) may not necessarily apply to carbonate source rocks. The siliceous lithofacies exhibit a similar n-alkane distribution but differ in the predominance of isoprenoids (more typical for this level of maturity) and pristane/phytane slightly greater than 1.0 [Fig. 9(B)]. The sample shown in Fig. 9(B) is also unusual in the high abundance of n-C2~; this is may be the result of co-elution with another (uncharacterized) hydrocarbon of probable biogenic origin. The clastic lithofacies are characterized by an abundance of n-alkanes in the range C25~C31with an odd-carbon predominance and pristane/phytane much greater than 1.0 [Fig. 9(C)], features that are characteristic of organic matter originating from higher plants (Hunt, 1979; Connan and Cassou, 1980). Sterane distributions of the three lithologies are also distinct. The steranes of the carbonate lithofacies [Fig. 10(A)] are characterized by a paucity of diasteranes and an abundance of ~/~/~ isomers, which is typical of carbonate source rocks (Palacas et al., 1984; Rullkotter et al., 1985; Mello et al., 1988). The siliceous lithofacies are dominated by the ~ct~ (20R) isomers [Fig. 10(B)]. This feature is more characteristic of immaturity (Mackenzie, 1984) than of an organic facies type, although the fact that its occurrence is limited to this lithofacies may be significant. The clastic lithofacies is enriched in diasteranes with the C29 isomers dominant [Fig. 10(C)]. This is consistent with the catalytic role of clays in diasterane formation (Rubinstein et al., 1975; Sieskind et al., 1979) and predominance of organic matter originating from higher plants (vitrinite contents up to

50%).

Hydrocarbon geochemistry of Cretaceous source rocks, Trinidad

1.5 1.0

Calcareous

A

% t

.~

o.5

cu

0

t'O

Calc A

Siliceous

£3

* S

CalcB Siliceous

Cla*stic

04

O -0.5 Q.. -1.0 -1.5

Calcareous

-1.5

-1.0

•

B -0.5

0

.Clastic 0.5

1.0

1.5

PC 1 ( 3 3 . 9 % )

Fig. 11. Scores crossplot of PC 1 versus PC 2 obtained from of extractable saturated and aromatic hydrocarbon

PCA

distributions in the three lithofacies identified. Samples are identified by lithofacies according to criteria described in the text. Numbers in parentheses represent fraction of total variance accounted for by each principal component.

The distributions of triterpanes, steranes and 2and 3-ring aromatic hydrocarbons were also analyzed by PCA. A scores crossplot of PC 1 versus PC 2 (Fig. 11) shows nearly complete separation of the three lithofacies (samples are identified by lithofacies in Fig. 11 according to the criteria established by PCA of major oxide and bulk organic parameters discussed earlier). The carbonate facies are discriminated from the siliceous and clastic facies by PC 1 and the siliceous and clastic facies are discriminated by PC 2. In addition, PC 2 indicates variations in composition within the carbonate samples.

0.2

453

Two groups, identified as 'A' and 'B', are defined based on positive and negative scores for PC 2 (Fig. 11). The loadings plot (Fig. 12) illustrates which hydrocarbons are important in distinguishing the various lithofacies as well as the covariance of different biomarker and aromatic hydrocarbon compound classes. The loadings are presented both as clusters consisting of structurally-related compound classes as well as individual compounds in order to facilitate display of the results. These associations define the organic facies corresponding to each lithofacies. Thus, carbonate organic facies are enriched in dibenzothiophenes (DBT), ctflfl steranes and tricyclic terpanes (all loaded negatively in PC 1). Carbonate facies 'B' can be distinguished from 'A' by an enrichment in phenanthrenes (methyl- and dimethyl isomers) relative to di- and trimethylnaphthalenes and by a slight enrichment in tricyclic terpanes (both loaded negatively in PC 2). Figure 13 contrasts the triterpane distribution of samples representing facies 'A' and 'B' and illustrates the enrichment in tricyclic terpanes in the latter. Facies 'B' also has lower contents of both 28,30-bisnorhopane and gammacerane (28H and G in Fig. 13). The enrichment of facies 'B' in both tricyclic terpanes and phenanthrenes is interesting in light of the fact that these compound classes share the same non-linear hydrocarbon ring skeleton. This suggests the possibility of a common precursor moiety in the kerogen structure.

~

BISNOR ac~x ~STER (20R)

GAM t",l

o

OLEANMORET ~ p ~ MeP,~" ~ ' I s -0.2

-0.4

-0.2

0

PHEN 0.2

PC I Fig. 12. Loadings crossplot of PC 1 versus PC 2 obtained from PCA of extactable saturated and aromatic hydrocarbon distributions. These loadings correspond to the scores shown in Fig. 11. The results are presented both as clusters of structurally-related compound classes as well as individual compounds. Abbreviations: DBT = dibenzothiophene; MeDBT = methyldibenzothiophenes; DMeN = dimethylnaphthalenes; TMeN = trimethylnaphthalenes; MeP = methylphenanthrenes; DMeP = dimethylphenanthrenes; OLEAN = oleanane; MORET = moretane; H35(R ) and H35(S) = 22R and 22S isomers of C35 extended hopanes. Other abbreviations are described in the text.

A. G. RF-OUEJOet al.

454

Several samples of the carbonate lithofacies exhibit high contents of extractable organic matter (EOM). These are identified by an asterisk inside the square symbols in Fig. 11, and represent samples containing greater than 30% EOM per unit TOC. These samples occur primarily in the AB-102 well and likely contain

in-migrated hydrocarbons which are not indigenous to the interval analyzed. Earlier, evidence was presented which suggested that staining did not affect maturity assessment based on Rock-Eval Tmax; this type of staining could, however, affect organic facies assessments. A consideration of the scores crossplot

Calcareous 'A'

301-1

28H 2 )H G

Tm

Calcareous 'B'

30H

2gH

21

23

Tm 24

20

G 26

Ts

28H

28 29

Fig. 13. Mass chromatograms of m / z 191 showing triterpane distributions in representative samples of calcareous facies 'A' and 'B'. Numbers over peaks denote the carbon number of tricyclic terpanes; numbers followed by the letter H denote carbon number of hopanes. G = gammacerane; Ts and Tm are trisnorneohopane and trisnorhopane, respectively.

Hydrocarbon geochemistry of Cretaceous source rocks, Trinidad in Fig. 11 indicates that these samples are intermediate in composition relative to others representing the lithofacies, including samples from the same well which show little evidence of staining. This suggests that the in-migrated hydrocarbons may represent short-range migration such as bitumen filling of fractures. In this case, the hydrocarbon characteristics of the samples would not be expected to differ significantly from other samples within the section. We have elected not to exclude these samples from the PCA organic facies model, although their extractable hydrocarbon attributes may not be entirely indigenous. The siliceous organic facies are characterized by an enrichment in ~ct~ (20R) steranes and 28,30-bisnorhopane (BISNOR in Fig. 12). These compounds are loaded positively in both PC 1 and PC 2 (Fig. 12). 25,28,30-Trisnorhopane also occurs widely in both this and carbonate facies 'A', although the abundance of this compound and 28,30-bisnorhopane do not covary systematically. An enrichment in these biomarkers is characteristic of source rock immaturity, although bisnorhopane and trisnorhopane have also been associated with anoxic depositional conditions (Grantham et al., 1980; Curiale et al., 1985; Mello et al., 1988). In a study of the Monterey Formation, Curiale and Odermatt (1989) found that siliceous lithofacies had lower bisnorhopane/hopane ratios than phosphate/carbonate lithofacies, a trend opposite that observed here. The relative abundance of this compound is apparently dependent on processes other than lithology. Among the aromatic hydrocarbons, dibenzothiophenes are less abundant in the siliceous facies than in the carbonate facies and diand trimethylnaphthalenes are enriched relative to phenanthrenes (Fig. 12). The clastic lithofacies contain a greater abundance of norhopane and hopane (NORHOP and HOP in Fig. 12) relative to steranes, reflecting elevated hopane/sterane ratios characteristic of higher-plant dominated organic facies (Hoffman et aL, 1984; Isaksen, 1991). Several other triterpanes are enriched in this lithofacies including trisnorneohopane (Ts), moretane and the non-hopanoid 18~ (H)-oleanane. The latter compound is derived from angiosperm plants and occurs widely in deltaic depositional environments (Ekweozor et al., 1979; Hoffman et al., 1984; Mello et al., 1988). All of these compounds are loaded positively in PC 1 and negatively in PC 2. Other molecular attributes which define this organic facies include an enrichment in phenanthrenes and low abundance of dibenzothiophenes and tricyclic terpanes. 28,30-Bisnorhopane and 25,28,30-trisnorhopane are absent from all the samples corresponding to this facies. The loadings plot in Fig. 12 also shows that diasteranes are not as important in defining this organic facies as are the other compound classes, despite the fact that they dominate sterane distributions [e.g., Fig. 10(C)] in several of the samples analyzed.

455

Visual kerogen descriptions (Table 3) further reinforce the organic facies defined by the hydrocarbon compositions for the various lithofacies. Most notably, vitrinite contents are highest (up to 50%) in the clastic lithofacies, as expected based on their greater clay content and hydrocarbon distribution indicative of higher plant organic matter. The carbonate lithofacies consist of 80% + unstructured, amorphous kerogen and contain only a trace of vitrinite. The siliceous lithofacies also contain predominantly unstructured kerogen but can contain up to 10% vitrinite. The distribution of individual compounds and compound classes shown in the PCA loadings crossplot in Fig. 12 can also be described in terms of conventional parametric ratios. For example, the aromatic hydrocarbon loadings would suggest low values for the ratio phenanthrene/dibenzothiophene (Phen/DBT) for both the siliceous and carbonate facies, while higher values would be typical of the clastic facies. The siliceous and carbonate facies, on the other hand, should exhibit higher values for the ratios naphthalene/phenanthrene (Naph/Phen) than the clastic facies. The crossplot of Phen/DBT versus Naph/Phen in Fig. 14 shows how this is indeed the case. The clastic facies can be readily discriminated using these parameters, however, there is overlap between the carbonate and siliceous facies. This example illustrates how the multivariate analytical approach, by taking into consideration the interrelationships between all measured variables, is superior to simple bivariate analysis in differentiating samples. Regional distribution o f lithofacies and organic facies

The regional distribution of the various lithofacies allows some generalizations regarding hydrocarbon source characteristics. Table 3 summarizes the attributes of the various organic facies defined. Carbonate facies 'A' and 'B' exhibit good petroleum potential, are similar lithologically and only differ subtly in their hydrocarbon distribution. These lithofacies were encountered in three wells: AB-102, ES-1 and GY-163. These wells are located in the Central Ranges and Southern Basin (Fig. 1) and are widely separated, which suggests that petroleum generated from carbonate source rocks may be found at various localities throughout southern Trinidad. The siliceous facies also exhibit excellent petroleum potential and are geochemically distinct from the carbonate facies. These lithofacies are present in the MR-I, ME-15 and MW-45 wells which are located in the Siparia Syncline region in south-central Trinidad (Fig. 1). The regional significance of this lithofacies as a petroleum source may be limited by the fact that in the ME-15 and MW-45 wells it occurs in thin intervals which may not be volumetrically significant. In the MR-1 well, however, this lithofacies is significantly thicker (Fig. 8). Based on its limited geographic occurrence, petroleum generated from this source would be expected primarily in south-central

MR-l; ME-15; MW-45

-1 Low Moderate High to moderate
ES-1; AB-102; GY-163

Paraffinic; C12-C25

<1 Low High Moderate
AB-102; GY-163

Aliphatic HC characteristics

Pds/Phy Diasterane content (~pp sterane content Tdcyclic terpanes 35/34 Hopanes Bisnorhopane Tdsnorhopane Gammacerane PhenlDBT

Wells where encountered

Paraffinic; C12-C25

Low Low

Low Low

AI203/TOC Th/U

>1 Low to moderate Low Low to moderate <1 High to moderate High High to moderate Moderate

Isoprenoids dominate; C12-C30

Low to moderate Low to moderate

Good to excellent oil II 80+% unstructured; 5-10% vitrinite

Good to excellent oil II/llS 85+% unstructured; trace vitdnite

Good to excellent oil II/IIS 80+% unstructured; trace vitdnite

Source potential Kerogen Type Kerogen composition

Siliceous

Calcareous 'B'

Calcareous 'A"

ATTRIBUTES

Table 3, Geochemical attributes of the Cretaceous lithofacies identified in this study

MD~4;MR~

>> 1 High to moderate Moderate Low << 1 Absent Absent Low High

Isoprenoids and C25-C31 dominate; high CPI

High High

Fair to poor oil III/11 5-50% vitrinite

Clastic

o

c~

Hydrocarbon geochemistry of Cretaceous source rocks, Trinidad

457

1.5

Calcareous

Siliceous

1.0 Clastic e~

Z

0.5

0

' 0

F 10

'

I 20

'

I 30

I 40

I 50

60

Phen/DBT Fig. 14. Crossplot of the ratios total naphthalenes/total phenanthrenes (Naph/Phen) versus total phenanthrenes/total dibenzothiophenes (Phen/DBT) for the three litho~cies.

Trinidad. The clastic lithofacies are present in the MR-I well and in the nearby MD-34 well (Fig. 1). This lithofacies has limited petroleum potential, however, any liquid hydrocarbons generated from this source would also be localized in south-central Trinidad. These generalizations assume that the present-day location of the Cretaceous intervals penetrated do not differ greatly from those of the effective source rocks during generation, which is thought to have begun during the middle Miocene (Rodrigues, 1986). This coincides with a period of tectonic activity during which much deformation occurred; thus, there is a possibility that present-day locations differ from paleolocations. SUMMARY

A geochemical study of Cretaceous source rocks from Trinidad has resulted in the following conclusions: 1. Organic-rich sediments which exhibit good to excellent potential for oil were deposited during the Campanian through Cenomanian. Sediments of Maestrichtian age with good source potential for oil are found in the AB-102 well. However, most Maestrichtian-age sediments analyzed can be classified as either poor oil/good gas sources or poor gas sources. 2. With few exceptions, the sediments analyzed can be classified as immature to early mature with respect to hydrocarbon generation. The highest vitrinite

reflectance values measured correspond to the onset of hydrocarbon generation. These results suggest that the effective source rocks which have generated the bulk of oil in Trinidad were not sampled in the study and are likely buried at greater depths. 3. Analysis of major oxides and trace elements shows that the Campanian through Turonian intervals exhibiting the best petroleum potential were deposited in clastic-starved environments. This is evidenced by the ratios AIzO3/TOC and Th/U, both of which are inversely correlated with petroleum potential. 4. Principal Components Analysis (PCA) of the combined TOC, Rock-Eval and major oxide data reveals three lithofacies--carbonate, siliceous and clastic--within samples exhibiting significant hydrocarbon source potential. The highest petroleum potential is associated with the siliceous and carbonate lithofacies, which reflect hemi-pelagic sediments deposited under low oxygen conditions. The clastic lithofacies have lower petroleum potential and represent nearshore sediments transported to the continental slope. Variations in lithofacies can be recognized both regionally and stratigraphically. 5. Extractable saturated and aromatic hydrocarbon compositions vary with lithology. PCA of biomarker and 2- and 3 -ring aromatic hydrocarbon distributions shows that the carbonate lithofacies are characterized by an abundance of ~/~/~ steranes and dibenzothiophenes. Two distinct organic facies can be recognized within the carbonate lithofacies that

A. G. REQUEJO et al.

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differ in their relative a b u n d a n c e o f tricyclic terpanes, g a m m a c e r a n e a n d b i s n o r h o p a n e . T h e siliceous lithofacies are characterized by a n a b u n d a n c e of b i s n o r h o pane, gag ( 2 0 R ) steranes a n d a slight e n r i c h m e n t in n a p h t h a l e n e s relative to p h e n a n t h r e n e s . The clastic lithofacies exhibits high h o p a n e a b u n d a n c e s relative to steranes, a n e n r i c h m e n t in m o r e t a n e a n d 18g (H)oleanane a n d a slight e n r i c h m e n t in p h e n a n t h r e n e s relative to naphthalenes. 6. Regional distribution o f the various lithofacies suggests t h a t c a r b o n a t e sourced oils m a y occur widely t h r o u g h o u t s o u t h e r n Trinidad. Oils generated from the siliceous a n d clastic lithofacies, however, m a y be localized in south-central Trinidad. Acknowledgements--We thank Exxon Production Research Company and Exxon Exploration Company for permission to publish. Marlene Schappes, Phuc Nguyen and Jan Herbst of EPR are acknowledged for technical support. Nils Teln~es assisted with some of the multivariate analyses. Paul Mankiewicz and Kevin Bohacs are acknowledged for valuable discussions regarding the concepts underlying chemical lithologies. REFERENCES

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G E O C H E M I S T R Y OF GAS A N D CONDENSATES