Influence of maturity on distributions of benzo- and dibenzothiophenes in Tithonian source rocks and crude oils, Sonda de Campeche, Mexico

PII:

Org. Geochem. Vol. 28, No. 7-8, pp. 423±439, 1998 # 1998 Published by Elsevier Science Ltd. All rights reserved Printed in Great Britain S0146-6380(98)00009-6 0146-6380/98 $19.00 + 0.00

In¯uence of maturity on distributions of benzo- and dibenzothiophenes in Tithonian source rocks and crude oils, Sonda de Campeche, Mexico D. SANTAMARIÂA-OROZCO12, B. HORSFIELD2*, R. DI PRIMIO2 and D. H. WELTE2 1

Mexican Institute of Petroleum, C.P. 07730, Mexico City, Mexico and 2Institute of Petroleum and Organic Geochemistry (ICG-4), Research Centre JuÈlich, 52425 JuÈlich, Germany (Received 22 November 1997; returned to the author for revision 13 January 1997; accepted 15 January 1998)

AbstractÐThe Sureste Basin is the most proli®c oil-producing area of Mexico, extending from the mainland into the Sonda de Campeche o€shore region. The Tithonian sedimentary sequence is the most important source of hydrocarbons. It contains sulphur-rich kerogen which progressively cracks to form petroleum beginning at 0.53% Rr. Maturity increases from northeast to southwest across the region. Sulphur-compounds in the Tithonian source rocks and in the petroleums they have generated have been studied by gas chromatography. Alkylbenzothiophenes are present in highest abundance at low maturity whereas the alkyldibenzothiophenes are most abundant at higher stages of maturity. The relative abundance of speci®c C3-benzothiophene isomers are especially sensitive to changes in maturity of sulphur-rich Type-II organic matter. A novel maturity parameter, the C3-benzothiophene index (C3BTI), shows a very good correlation to vitrinite re¯ectance values (R2 3 0.96, n = 10). The methyldibenzothiophene ratio MDR' also has a wide dynamic range. Application of C3BTI and MDR' to the study area strongly supports a model involving localised vertical migration avenues, though several possible scenarios may explain the ®lling history of reservoirs in the southwest part of the Sonda de Campeche. # 1998 Published by Elsevier Science Ltd. All rights reserved Key wordsÐGulf of Mexico, benzothiophenes, dibenzothiophenes, maturity parameters, carbonate source rocks

INTRODUCTION

The Sureste Basin is the most proli®c oil-producing area of Mexico, extending from the mainland into the Sonda de Campeche o€shore region (Fig. 1). The origin of the Sureste Basin is not precisely known, but there is general agreement that it was formed during the opening (rifting) of the Gulf of Mexico, which began during the Early Jurassic. The onset of extensional tectonism resulted in a regional crustal downwarping as indicated by ¯uvial/aeolian sandstones in the study area. During the Middle Jurassic evaporites were deposited due to restricted marine in¯ux and a hot-arid climate. From the Late Jurassic to the present day, marine sediments formed successive carbonate-terrigenous shelf complexes. The Late Jurassic is characterized by sandstones, anhydrites, limestones and shales. The Cretaceous is represented by limestones and dolomites. Finally, in the Cenozoic, carbonate breccias, bentonites, shales, sandstones and siltstones were deposited. The Tithonian sedimentary sequence is the most important source of hydrocarbons in the Sureste *To whom correspondence should be addressed. 423

Basin (HolguõÂ n, 1987). It consists of massive calcareous black shales and dark grey, clayey laminated mudstones, averaging 220 m thickness, deposited under anoxic conditions on a marine carbonate shelf (Angeles-Aquino, 1987). Large volumes of the Tithonian source rocks are mature and this is the probable cause of overpressure in parts of the basin (GonzaÂlez and HolguõÂ n, 1991). A vitrinite re¯ectance range of 0.4±1.3% has been reported for the Sonda de Campeche, with maturity levels increasing to the south and west (SantamarõÂ a et al., 1995). Crude oil was expelled from Tithonian source rocks into the Kimmeridgian through Pliocene section (GuzmaÂn et al., 1994) and accumulated mainly in calcareous breccias of the Lower Paleocene (Santiago and Baro, 1990). This took place from the Oligocene in the onshore Reforma-Tabasco area southwest of the Sonda de Campeche, through to the present-day in the northern part of the Sonda de Campeche (HolguõÂ n, 1987). Low gravity crude oils of the Sonda de Campeche are rich in sulphur whereas higher gravity crudes are depleted in sulphur (cf. Orr, 1978; Baskin and Peters, 1992). Migration pathways are strongly vertical along high-angle faults and fractures (HolguõÂ n, 1987; GonzaÂlez and HolguõÂ n, 1991; Demaison and

Fig. 1. Map showing the Sonda de Campeche study area and locations from which Tithonian source rocks and Paleocene-reservoired crude oils were obtained.

424 D. SantamarõÂ a-Orozco et al.

In¯uence of maturity on distribution in Tithonian source rocks and crude oils

Huizinga, 1993). Individual petroleum accumulations in series of tilted fault blocks can therefore be considered to be locally sourced. It is the close spatial relationship between active source and petroleum accumulation and the essential absence of lateral migration, that makes the Sonda de Campeche very attractive for studying the molecular relationships between source rocks and petroleums. To this end, the prime goal of the current contribution was to investigate the occurrence of organic sulphur-containing compounds in Tithonian source rocks and their generated crude oils. The outcomes are that a new maturation parameter based on the C3-benzothiophenes is proposed and that various possible reservoir-®lling scenarios could be evaluated. SAMPLES AND METHODS

A total of 35 Tithonian core samples and 17 crude oils from 22 wells in the Sonda de Campeche were included in the study. The core samples were subjected to preliminary screening by LECO and Rock-Eval (Table 1) in order to document basic source rock properties and select a reduced number of samples for more detailed analysis. Rock-Eval pyrolysis was performed in duplicate. Total organic carbon (TOC)

425

was determined on decarbonated samples and total carbon (TC) on whole rock samples using duplicate LECO analyses. A rough measure of carbonate content was determined using (TC ÿ TOC)*8.33, the stoichiometry being based on CaCO3. Organic petrology was performed using a Zeiss Photomicroscope III. The microscopic description of the organic matter was made using polished whole rock samples, orientated perpendicular to bedding, in both incident white light and ¯uorescence modes (¯uorescence excitation wavelength band 350±420 nm) at magni®cations between 100 and 1000  . Nomenclature was taken from Stach et al. (1982). Vitrinite was identi®ed by its optical properties and morphology. Mean random vitrinite re¯ectance (see Table 2) was determined for selected samples from total maceral re¯ectance histograms with reference to the aforementioned characteristics (see Appendix A). Re¯ectance suppression was not considered to have been signi®cant based on interpolations using pro®les through the entire stratigraphic column for several wells (Pemex, unpublished data). Selected samples were extracted with dichloromethane/methanol (99:1, v/v) using a modi®ed ``¯ow blending'' method (Radke et al., 1978). That portion soluble in hexane (maltenes) was separated by medium pressure liquid chromatography

Table 1. Rock-Eval data for Tithonian source rocks of the Sonda de Campeche. sorted according to well number and position along the NE±SW trend discussed in the text Well A A A A A B B C C C D D E E F F F F G G G G H H H I I J J J J J K K K

E number TOC (%) CaCO3 (%) S1 (mg/g) E-41491 E-41492 E-41493 E-41494 E-41495 E-41502 E-41503 E-41524 E-41525 E-41526 E-41448 E-41449 E-41511 E-41512 E-41456 E-41457 E-41458 E-41459 E-41464 E-41465 E-41466 E-41467 E-41488 E-41489 E-41490 E-41440 E-41441 E-41496 E-41497 E-41498 E-41499 E-41500 E-41507 E-41509 E-41510

5.39 17.90 1.62 2.86 22.80 4.41 4.09 6.70 5.02 7.28 4.68 4.60 2.94 2.94 2.63 3.30 4.04 5.00 1.66 1.84 2.96 2.68 3.40 0.40 0.41 1.42 1.52 2.43 0.19 1.23 0.65 3.02 1.64 3.66 2.55

48.42 27.50 89.83 86.17 3.33 67.42 64.25 50.00 44.83 46.00 79.33 64.17 45.58 73.00 71.42 65.00 37.67 16.58 83.67 64.50 82.00 40.25 40.92 87.50 78.83 53.17 74.83 88.92 96.75 91.42 93.75 83.17 70.50 45.25 50.08

1.40 4.98 0.20 0.53 4.96 0.89 0.68 1.15 0.92 1.51 4.55 5.06 1.99 2.10 3.64 4.63 4.89 6.31 2.48 2.51 5.09 3.28 3.40 0.25 0.26 0.85 0.63 0.71 0.05 1.80 1.80 0.74 0.66 1.27 1.22

S2 (mg/g) 37.84 122.93 9.70 18.47 171.57 29.88 26.60 42.71 30.41 46.96 22.40 23.56 12.16 12.17 8.13 11.01 12.67 16.85 5.59 6.10 11.55 9.54 11.41 0.47 0.50 1.44 2.11 2.00 0.05 1.14 0.57 2.49 0.58 1.55 1.19

S3 (mg/g) 1.07 1.79 0.77 1.08 1.97 0.81 0.79 2.64 2.65 3.68 0.41 0.25 0.15 0.11 0.28 0.33 0.37 0.40 0.26 0.32 0.33 0.43 0.31 0.34 0.26 0.23 0.11 0.37 0.00 0.25 0.11 0.19 0.33 0.28 0.25

Tmax (8C) 412 415 405 405 409 415 416 418 414 416 434 435 434 438 432 434 434 433 430 432 429 431 436 435 433 436 441 450 440 441 436 452 549 467 469

PI

HI

OI

Lithology

0.04 0.04 0.02 0.03 0.03 0.03 0.02 0.03 0.03 0.03 0.17 0.18 0.14 0.15 0.31 0.30 0.28 0.27 0.31 0.29 0.31 0.26 0.23 0.35 0.34 0.37 0.23 0.26 0.50 0.61 0.76 0.23 0.53 0.45 0.51

702 687 599 646 753 678 650 637 606 645 479 512 414 414 309 334 314 337 337 332 390 356 336 118 122 101 139 82 26 93 88 82 35 42 47

20 10 48 38 9 18 19 39 53 51 9 5 5 4 11 10 9 8 16 17 11 16 9 85 63 16 7 15 0 20 17 6 20 8 10

marl calcareous shale limestone limestone shale shaly limestone marl marl marl marl shaly limestone marl marl shaly limestone shaly limestone marl marl shale shaly limesntone marl shaly limestone marl marl limestone shaly limestone marl shaly limestone limestone limestone limestone limestone shaly limestone shaly limestone marl marl

426

D. SantamarõÂ a-Orozco et al. Table 2. Additional bulk geochemical and petrographic characteristics of Tithonian source rocks

Well

Number

A A B C D E F G H I J K

E-41495 E-41492 E-41502 E-41525 E-41449 E-41511 E-41459 E-41466 E-41488 E-41440 E-41500 E-41509

Extract Sat (mg/g (mg/g TOC) TOC) 91 79 75 45 836 456 676 792 492 208 49 44

<1 1 3 2 79 13 146 118 102 71 14 20

Aro (mg/g NSO (mg/g not recovered TOC) TOC) (mg/g TOC) 3 7 10 3 198 23 119 167 95 39 10 57

20 37 34 16 374 52 272 343 185 44 8 5

(MPLC, Radke et al., 1980) into saturate, aromatic and NSO fractions. Crude oils (see Table 4 for listing) were fractionated after asphaltene precipitation in n-hexane. Benzothiophenes and dibenzothiophenes were contained in the aromatic fraction. Gas chromatographic analysis of the aromatic fraction was performed using a HP 5890 Series II GC equipped with a fused silica capillary column (Ultra #2; 50 m  0.2 mm). The carrier gas was helium with a ¯ow rate of 1 ml/min. The oven temperature was programmed from 1208C (2 min) to 3108C at 38C/min. The concentration of selected benzothiophenes and dibenzothiophenes was determined by a combination of a ¯ame ionisation detector and a sulphur selective detector (Hall1 electrolytic conductivity detector HECD), as described previously for a petroleum (Nishioka et al., 1986). The data were processed using a computerized VG Multichrom system. The concentration of selected benzothiophenes and dibenzothiophenes was determined by a combination of a ¯ame ionisation detector and a sulphur selective detector (HALL1 electrolytic conductivity detector HECD). 1-ethylpyrene (FID), 1-butylpyrene (FID) and dibenzothiophene (FID and HALL) were used as standards. GC±MS analysis of the aromatic fraction was carried out on a Finnigan MAT 95 SQ instrument in order to verify C3-benzothiophene recognition and rule out the possibility of co-eluting compounds. The mass spectrometer was connected to a HP 5890 Series 2 gas chromatograph equipped with a fused silica capillary column (50 m  0.25 m, 0.33 mm ®lm thickness). The oven temperature was programmed from 1108C (5 min) to 3108C at 38C/ min. The ®nal temperature was maintained for 18 min. Helium was used as carrier gas. The mass spectrometer was operated in EI mode at an ionisation energy of 70 eV and a source temperature of 2608C. Data acquisition and processing was accomplished with a Finnigan ICL system, Version 10.0.

67 35 27 24 185 367 139 165 109 54 17 13

Rr (%) 0,35 0,35 0,36 0,38 0,49 0,57 0,65 0,75 0,85 0,91 1,09 1,29

Liptinite (%) 77 74 91 88 89 85 92 93 91 94 90 87

Vitrinite (%) 18 21 7 8 9 12 6 5 7 3 5 6

Inertinite (%) 5 5 2 4 2 3 2 2 2 3 5 7

RESULTS AND DISCUSSION

Type and maturity of organic matter in Tithonian source rocks The potential source lithofacies of the Tithonian, comprising marls, shales, calcareous shales and shaly limestone, display a broad range in TOC values extending from 1.42 to 22.80% (Table 1). Interbedded limestones are poorer in organic carbon. No regional trends in source richness were discernable. Kerogen type, on the other hand, shows a pronounced regional pattern. The northern part of the study area is characterized by high hydrogen indices (HI) around 500 to 750 mg HC/g TOC and oxygen indices (OI) in the range of 10 to 53 mg CO2/g TOC, the central area by intermediate HI values from 330 to 420 and an OI range from 5 to 16 and the southern part by HI values from 40 to 330 and an OI range from 9 to 21 (see Fig. 1 and Table 1; also Santamarõ a et al., 1995). Microscopic observations and vitrinite re¯ectance measurements indicate this is related to both maturity and organic facies. As reported by Santamarõ a et al. (1995) there are three di€erent organic facies in the Sonda de Campeche. The ®rst is located in the northern part and consists mainly of yellow alginites within amorphous organic material, liptodetrinite, bituminites and red chlorophyllinites. The second is found in the central area and shows a relatively high content of dark yellow alginite, a relatively low content of amorphous organic material content, and the presence of liptodetrinites. In this zone the remains of ®sh bones are a common microscopic constituent. Finally, the southern part of the study area is characterized by scarce orange to brown liptodetrinite (possibly alginites) and calcareous radiolaria. The three zones are thought to correspond to anoxic marine shelf environments with three di€erent water depths. Decreasing HI is matched by increasing values of vitrinite re¯ectance. The northern area is immature,

In¯uence of maturity on distribution in Tithonian source rocks and crude oils

427

Fig. 3. Extract yields as a function of vitrinite re¯ectance, for Tithonian source rocks of the Sonda de Campeche. Fig. 2. HI vs Rr diagram for Tithonian source rocks from the Sonda de Campeche, Mexico. Datapoints from previous studies of the Hils Syncline (RullkoÈtter et al., 1988) and Bakken Shale (Muscio et al., 1994) are shown for comparison.

as indicated by vitrinite re¯ectance values <0.5% Rr; in this region there is no oil production. In the central area, vitrinite re¯ectance values cover the range (0.5% < Rr<1.0%) generally considered to represent the oil window, including peak petroleum generation. Most production in the Sonda de Campeche comes from this region. The southern area is late mature to overmature, as indicated by vitrinite re¯ectance values greater than 1.0% Rr and here only light oil, gas and condensate are produced. The relationship between vitrinite re¯ectance and HI is closely similar to that reported previously for other source rocks (Fig. 2). Based on the screening data twelve source rock cores were selected as being representative of the regional geochemical framework, covering the entire hydrogen index± oxygen index evolution path for Type II kerogen and a broad vitrinite re¯ectance range (Rr=0.36± 1.29%). Bitumen contents were generally high and even exceedingly high (208±835 mg/g TOC) for the maturity range 0.49±0.91Rr (Table 2). Extract yield as a function of vitrinite re¯ectance allows an apparent ``oil window'' to be discerned (Fig. 3). To what exact degree this is in¯uenced by generation, outward migration (expulsion/depletion), inward migration (staining) or intra-formational migration is hard to prove. While the high values are entirely consistent with the presence of migrated petroleum in clastic source rocks, this is not the case for carbonate and siliceous source rocks for which high yields of indigenous extract have been reported, especially where organic sulphur was abundant

(Powell, 1984; Sinninghe Damste et al., 1989; RullkoÈtter et al., 1990; di Primio, 1995). Decreasing relative yields of thiophenes in pyrolysates (Santamaria, unpublished data) are consistent with the hypothesis that the bitumens were generated locally and did not permeate through the entire sedimentary section from a deep source. With regard to this point, the Oxfordian has been said to be a subsidiary source in some parts of the Sonda de Campeche (GonzaÂlez and Holguõ n, 1991), but the overpressured nature of the Tithonian makes this option very unlikely. The bitumen composition changes systematically in the three zones of the study area described above (Table 2). Bitumens from the northern part of the study area contain highest proportions of NSO compounds whereas further south saturated hydrocarbons predominate and NSO compounds are in minor abundance. Distribution of benzothiophenes and dibenzothiophenes The concentrations of benzothiophenes (BT) and dibenzothiophenes (DBT) in the source rocks show interesting features related to maturity (Table 3), as shown in Fig. 4. The BT data spread tracks the ``oil window'' de®ned by total extract yield to a large degree (cf. Figure 3) with highest concentrations occurring at lower maturities. By contrast, DBT yields increase to a maximum at 0.91% and decrease beyond this maturity level. It is interesting to note that both the BT and DBT traces may be bimodal, with the two maxima discernable for the BT distribution occurring around 0.49% Rr (dominant) and 0.75% Rr and those for the DBT around 0.70% and 0.91% Ro (dominant). While bimodal distributions have been noted previously for total extract and aromatic hydrocarbon yields for the hydrous pyrolysis of a similar sulphur-rich source

428

D. SantamarõÂ a-Orozco et al.

Table 3. Benzothiophene and dibenzothiophene yields (mg/g TOC) of Tithonian source rock samples from the Sonda de Campeche, the peak numbers are listed in Fig. 6 Benzothiophenes Sample/ peak

5

E-41492 5 E-41495 <1 E-41502 41 E-41525 n.d. E-41449 22 E-41511 3 E-41459 0 E-41466 3 E-41488 1 E-41440 2 E-41500 2 E-41509 n.d.

6

7

8

9

10

11

12

13

14

15

16

17

18

19

Sum BTs

10 <1 27 n.d. 46 5 0 7 1 3 2 n.d.

4 <1 20 n.d. 33 8 1 16 3 4 2 n.d.

6 <1 26 n.d. 76 13 3 33 6 10 6 n.d.

18 <1 50 n.d. 125 28 5 47 6 11 5 n.d.

3 <1 31 n.d. 101 84 9 74 18 18 7 n.d.

6 <1 19 n.d. 28 15 3 14 3 4 2 n.d.

9 <1 16 n.d. 73 19 10 34 5 7 3 n.d.

5 <1 15 n.d. 66 27 21 53 9 18 11 n.d.

10 <1 27 n.d. 72 16 7 19 2 5 1 n.d.

6 <1 11 n.d. 35 16 5 15 3 3 1 n.d.

5 <1 7 n.d. 57 8 14 41 3 4 2 n.d.

3 <1 10 n.d. 93 62 49 115 26 36 12 n.d.

2 <1 12 n.d. 100 51 54 118 18 18 6 n.d.

7 <1 9 n.d. 50 22 22 26 4 5 1 n.d.

100 1 280 n.d. 960 380 200 610 110 150 62 n.d.

Dibenzothiophenes Sample

20

E-41492 n.d. E-41495 n.d. E-41502 10 E-41525 4 E-41449 23 E-41511 41 E-41459 34 E-41466 39 E-41488 13 E-41440 68 E-41500 61 E-41509 7

21

22

23

24

25

26

27

28

29

30

31

Sum DBTs

n.d. n.d. 7 5 43 45 73 74 26 160 140 26

n.d. n.d. 6 3 40 34 72 69 24 140 120 17

n.d. n.d. 17 4 50 39 53 53 15 66 30 1

n.d. n.d. 1 1 14 17 24 19 7 33 19 1

n.d. n.d. 2 2 22 22 46 43 13 110 85 32

n.d. n.d. 5 2 26 26 36 34 11 63 50 14

n.d. n.d. 4 3 41 39 89 84 25 130 120 27

n.d. n.d. 4 1 27 16 50 51 11 73 55 10

n.d. n.d. 9 4 71 48 100 95 23 120 60 4

n.d. n.d. 4 1 38 22 56 57 12 65 41 5

n.d. n.d. 1 1 20 20 33 26 8 34 19 3

n.d. n.d. 70 31 420 370 660 640 190 1100 790 150

rock (di Primio et al., 1993; di Primio, 1995), their presence here remains unproven because sampling densities are too low. The fact that benzothiophenes are more abundant at low maturity whereas dibenzothiophenes are more abundant at high maturity is nicely illustrated by the strong decrease in the BT/DBT ratio with increasing maturity [Fig. 5(a)], corroborating the results of Ho et al. (1974). Because the curve shows very little scatter with increasing maturity, facies variations must be slight or have essentially no in¯uence on the ratio. Figure 6 shows six representative partial chromatograms of aromatic fractions, two for each maturity zone. On the left are the benzothiophenes and on the right the dibenzothiophenes. Of the 19 benzothiophene peaks emphasized in black, 9 belong to the C3-alkylbenzothiophene series, as veri®ed by GC±MS analysis. Identi®cation of the individual C3-alkylbenzothiophenes is dicult, because the number of possible isomers (62) is much larger than the number of peaks resolved by capillary GC. At present we have determined that 2,5,7-trimethylbenzothiophene contributes to peak 12, that 2,3,6-trimethylbenzothiophene contributes to peak 18 and that 2,3,4-trimethylbenzothiophene contributes to peak 19. In the C2 series, the 2,3- and 2,4- dimethylbenzothiophenes were generally the most prominent (peaks 7, 10), while in the C3 series, peak 17 was

almost always the most abundant. The identities of the dibenzothiophene peaks 20±25 are known but 26±31 are as yet unidenti®ed.

Fig. 4. Evolution of free sulphur compound abundances (benzothiophenes and dibenzothiophenes) during maturation of Tithonian source rocks.

In¯uence of maturity on distribution in Tithonian source rocks and crude oils

429

Fig. 5. The benzothiophene/dibenzothiophene ratio as a function of maturity. (a) Tithonian source rocks and (b) Paleocene-reservoired crude oils.

Maturity parameters based on the benzothiophenes and dibenzothiophenes Sulphur-compounds are sensitive over a wider maturity range than alkylnaphthalenes and alkylphenanthrenes, especially in the low maturity part of the spectrum (Radke et al., 1986; Radke and Willsch, 1994). The ratios of selected methyldibenzothiophenes with dibenzothiophene (the methyldibenzothiophene ratios MDR1, MDR2,3 and MDR4; see Appendix B for de®nition) have been

shown to vary as a function of maturity within a sequence from the Western Canada Basin, whereby MDR2,3 and MDR4 show an increase with maturity and MDR1 shows a decrease (Radke et al., 1982). There is a switch from the 1-methyl to the thermodynamically more stable 4-methyl isomer (Radke et al., 1986; Radke and Willsch, 1994) as expressed by increasing values of the methyldibenzothiophene ratios MDR and MDR' (4 MDBT/1MDBT) and 4-MDBT/(1-MDBT+4-MDBT), respectively). Both have been said to be versatile

430

D. SantamarõÂ a-Orozco et al.

Fig. 6Ðcaption on opposite page

In¯uence of maturity on distribution in Tithonian source rocks and crude oils

maturity parameters, with a sudden increase in the ratio marking the onset of intense C15+generation. The ethyldibenzothiophene ratio (EDR'), based on the ratio of 4,6-DMDBT/(4-EDBT + 4,6DMDBT) has also been proposed as a useful maturity parameter (Radke and Willsch, 1994). The applicability of all these parameters to the Tithonian of the Sonda de Campeche is considered in Fig. 7. Both the MDR and MDR' ratios show a very good correlation to Rr [Fig. 7(d) and (e)], though at low maturity the trend is not quite as tight. MDR1, MDR2,3, MDR4 and especially EDR' show appreciable scatter and have very limited use as maturation parameters for these source rocks. The analysis of the benzothiophenes has up to now concentrated mainly on the C1 and C2 isomers. Radke and Willsch (1991) showed that the distributions of the benzothiophenes can also be used for the interpretation of early stages of thermal evolution and introduced the methylbenzothiophene ratio [MBR = (5-MBT+6-MBT+7-MBT)/(2-MBT+ 3 - MBT + 4 - MBT + 5 - MBT + 6 - MBT + 7 - MBT)]. They observed that the occurrence and thermal evolution of extractable benzothiophenes in source rocks with Type II kerogens (Posidonia Shale from Germany) are signi®cant only in early maturity stages. They mentioned that variations in BT distributions in the interval of 0.3 to 0.5% Rr could only be tentatively attributed to maturity variations due to inadequate sensitivity of Rr. In the case of the Tithonian source rocks analysed in this study, C3alkylbenzothiophenes proved to be abundant in all samples and were the most prominent benzothiophenes in extracts from mature and overmature source rocks. Furthermore, they showed systematic changes in the isomer distribution with increasing maturity. As is readily observed in Fig. 6, the relative abundances of peaks 13, 17 and 18 increase relative to the other C3-alkylbenzothiophene peaks, especially 12, 14, 16, 17, 18 and 19. A ratio involving six of these C3-alkylbenzothiophene peaks, termed the C3-benzothiophene index (C3BTI) was found to show a very good correlation to %Rr over the entire range of maturity (Fig. 8), with a linear correlation coecient of R2 3 0.96.

431

Table 4. Bulk properties of crude oils from the Sonda de Campeche derived from Tithonian source rocks Well

Sample

API

M N O P Q R R S T T U U U V V W

E-41533 E-41531 E-41532 E-41543 E-41544 E-41535 E-41534 E-41537 E-41528 E-41527 E-41538 E-41541 E-41542 E-41545 E-41547 E-41536

28 10 11 23 31 12 32 33 26 29 24 26 39 38 33 27

C3 BTI ˆ

S (%)

13 ‡ 17 ‡ 18 … peaks† 12 ‡ 16 ‡ 19 … peaks†

2.10 4.03 2.18 1.63 1.50 3.61 1.68 0.69 1.38 0.65 2.02 1.74 0.31 0.24 0.11 0.71

…1†

Data for two clastic immature source rock samples of the Posidonia Shale ®t the same trend (Fig. 8). The index seems to be well suited for assessing the maturity of marine sulphur-rich source rocks in a broad maturity range covering 0.35 to 1.09% Rr and is here superior to maturity parameters based on the DBTs. We can only speculate at the mechanisms involved because the speci®c isomers involved are not known. However, we can suggest by analogy with DBTs and methylphenanthrenes (Radke et al., 1982; Radke and Willsch, 1994) that changes in the abundances of isomers are caused by di€erences in thermodynamic stability. Application to petroleums The 17 crude oils under study were obtained from wells across the entire Sonda de Campeche (cf. Table 4; Fig. 1). The physical characteristics of these oils showed an empirical correlation to geographic setting, with viscous semi-solids (low API gravity, high sulphur) in the far northeast, a range of intermediates in the central region and low viscosity liquids (high API gravity, low sulphur content) in the southwest. The inverse relationship between API gravity and sulphur content (Table 4) matches published trends (Evans et al., 1971;

Fig. 6. Partial capillary gas chromatograms obtained by electrolytic conductivity detector (Hall) to show the distribution of C10+aromatic sulphur compounds in immature, mature and overmature rock samples. Peaks selected for quanti®cation are indicated by numbers. (1) 2-methylbenzothiophene; (2) 3plus 4-methylbenzothiophene; (3) 2,7-dimethylbenzothiophene; (4±5) unidenti®ed C2-alkylbenzothiophenes; (6) 2,5+2,6-dimethylbenzothiophene; (7) 2,4-dimethylbenzothiophene; (8±9) unidenti®ed C2-alkylbenzothiophenes; (10) 2,3-dimethylbenzothiophene; (11) unidenti®ed C3-alkylbenzothiophene; (12) includes 2,5,7-trimethylbenzothiophene; (13±17) unidenti®ed C3-alkylbenzothiophenes; (18) includes 2,3,6-trimethylbenzothiophene; (19) includes 2,3,4-trimethylbenzothiophene; (20) dibenzothiophene; (21) 4-methyldibenzothiophene; (22) 2- plus 3-methyldibenzothiophene; (23) 1-methyldibenzothiophene; (24) ethyldibenzothiophene; (25) 4,6-dimethyldibenzothiophene; (26±31) unidenti®ed C2-alkyldibenzothiophenes.

432

D. SantamarõÂ a-Orozco et al.

Fig. 7. Established aromatic sulphur-compound parameters determined for Tithonian source rocks: (a) 1-methyldibenzothiophene ratio MDR1, (b) 2 + 3-methyldibenzothiophene ratio MDR2,3, (c) 4methyldibenzothiophene ratio MDR4, (d) methyldibenzothiophene ratio MDR, (e) methyldibenothiophene ratio MDR', (f) ethyldibenzothiophene ratio EDR.

Baskin and Peters, 1992). As stated earlier, this northeast-southwest regional pattern in crude oil properties resembles that of the maturity zones established for source rocks in a broad sense.

The C3BTI ratio calculated for the crude oils was converted to equivalent vitrinite re¯ectance (Rc) using the correlation for Tithonian source rocks shown in Fig. 8. The range for the entire oil suite

In¯uence of maturity on distribution in Tithonian source rocks and crude oils

433

Fig. 8. C3BTI as a function of maturity (Rr) for Tithonian source rocks.

Table 5. Benzothiophene and dibenzothiophene yields (mg/g oil) of crude oil samples in the Sonda de Campeche. Peak numbers and identi®cations are as listed in Fig. 6 Benzothiophenes Sample/ peak

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

Sum BTs

E-41532 E-41535 E-41531 E-41527 E-41528 E-41543 E-41542 E-41538 E-41541 E-41544 E-41536 E-41534 E-41547 E-41537 E-41545 E-41533 E-41546

5 36 69 20 29 14 21 16 17 20 16 20 44 17 15 28 35

25 67 120 34 56 39 22 38 48 34 21 29 39 33 27 65 56

52 49 51 46 54 46 29 64 71 57 21 46 19 41 21 37 31

50 120 84 100 100 83 54 120 150 90 55 82 45 82 56 66 85

98 180 188 108 139 91 40 171 188 117 35 100 16 96 34 140 44

170 230 170 220 270 240 86 330 370 250 87 230 38 190 81 230 120

75 82 100 66 78 62 24 68 85 57 24 49 14 40 16 69 18

80 120 110 86 93 86 35 140 150 87 37 81 24 69 29 100 31

110 110 120 110 120 110 76 210 200 120 52 100 24 110 37 100 36

56 120 120 61 75 74 15 78 110 72 21 62 9 46 13 82 10

48 88 65 62 85 83 13 82 89 65 23 57 7 41 14 73 12

41 80 65 44 54 46 23 101 80 54 15 46 6 39 11 39 8

230 170 140 320 330 280 150 510 560 300 180 270 94 270 140 180 120

220 220 150 210 260 260 82 370 410 250 86 220 35 200 82 180 57

84 69 93 57 76 76 25 110 120 72 31 59 6 47 18 100 11

1300 1700 1700 1600 1800 1600 700 2400 2600 1600 700 1500 420 1300 600 1500 700

Dibenzothiophenes Sample/ peak

20

21

22

23

24

25

26

27

28

29

30

31

Sum DBTs

E-41532 E-41535 E-41531 E-41527 E-41528 E-41543 E-41542 E-41538 E-41541 E-41544 E-41536 E-41534 E-41547 E-41537 E-41545 E-41533 E-41546

130 61 60 240 150 190 310 55 190 170 200 190 104 270 190 240 49

180 90 150 540 230 300 610 180 320 300 400 340 270 480 400 310 87

140 72 110 340 170 250 540 170 270 250 320 290 170 420 300 250 52

150 84 120 220 170 150 100 110 190 120 160 120 50 130 95 240 20

47 29 43 94 66 70 95 62 100 68 110 66 29 100 63 82 14

100 47 83 320 120 170 410 120 200 200 250 220 180 340 260 120 41

90 61 81 200 120 120 250 100 170 120 160 140 99 200 160 120 16

220 84 140 420 220 260 480 260 240 290 370 320 170 430 310 230 40

83 49 58 120 94 110 270 110 160 140 150 140 62 210 130 77 22

220 110 170 350 280 210 190 200 300 200 320 200 130 230 160 280 25

95 65 77 160 130 130 160 120 210 130 160 120 69 150 100 110 25

57 34 59 120 90 75 100 78 100 73 120 80 35 98 70 77 14

1500 800 1200 3100 1800 2000 3500 1600 250 2000 2700 2200 1400 3100 2200 2100 400

434

D. SantamarõÂ a-Orozco et al.

was 0.49±0.92% Rc and there was a positive relationship of C3BTI, Rc and API gravity. The least mature oil (108 API) had a C3BTI of 1.59 (Fig. 8), which is higher than the ratios monitored for the immature source rock extracts and may be taken as an indication of the maturity level necessary (0.49% Ro) for petroleum generation and expulsion from the Tithonian source rock sequence analysed. Using the same approach with MDR', the best of the methyldibenzothiophene ratios, the calculated maturity range was in good general agreement, though a little higher, at 0.59±1.10% Rc. Maturity patterns for crude oils and underlying Tithonian source rocks is shown in Fig. 9 and Table 6. Their overall similarity supports the model that secondary migration proceeded predominantly vertically via high angle faults and that little or no lateral migration occurred (HolguõÂ n, 1987; GonzaÂlez and HolguõÂ n, 1991; Demaison and Huizinga, 1994). Further con®rmation comes from the relative concentrations of benzothiophenes and dibenzothiophenes in the crude oils as a function of maturity [Fig. 5(b)] which, with the exception of two outliers (outside the stippled area), closely resemble the trend seen for the source rocks [Fig. 5(a)]. If it is assumed that C3BTI values directly signal the maturity of the source rocks at the time of petroleum expulsion, it could be deduced that expulsion must have occurred at progressively higher maturities in going from northeast to southwest. For this to be true a substantial and progressive

change in source rock properties such as rock fabric, organic matter richness and type, would have to occur. For instance, diminished source richness and the presence of mainly Type III kerogen has been said to favour delayed expulsion at higher maturity kerogen in other regions (Leythaeuser et al., 1983; Cooles et al., 1986). There is no evidence to support this possibility in the Sonda de Campeche because all kerogens fall on the maturity evolution trend for Type II marine organic matter at both bulk (RockEval) and molecular (Py±GC) levels (Santamarõ a, unpublished) and the facies di€erences seen petrologically (Santamarõ a et al., 1995) are relatively small. It is more reasonable to expect that petroleum expulsion began at roughly the same maturity level for all points in the basin but that this occurred at di€erent times depending on subsidence rate and temperature conditions and that the oils re¯ect the average composition of petroleums trapped up to the current maturity level. Thus, in the northeast, where source rock maturities are rather low (Rr values 0.5±0.75%), there is a more or less 1:1 correspondence between source rock and oil maturity. Petroleum expulsion took place here most recently. By contrast, petroleum expulsion probably began much earlier in the southwest (Holguõ n, 1987) and present-day oil compositions re¯ect reservoir ®lling over a much broader source rock maturity range. In this part of the Sonda de Campeche oil maturities are generally lower than that of the source rocks, with Rc being about 70% of Rr for the as-

Table 6. Aromatic sulphur-compound maturity parameter data of Tithonian source rocks and associated oils Well

E-Number

BT/DBT

MDR1

MDR23

MDR4

A A B C D E F G H I J K

E-41495 E-41492 E-41502 E-41525 E-41449 E-41511 E-41459 E-41466 E-41488 E-41440 E-41500 E-41509

n.d. n.d. 4.60 n.d. 2.35 1.03 0.31 0.96 0.58 0.14 0.08 0.00

n.d. n.d. 1.71 0.92 2.15 0.95 1.58 1.36 1.19 0.97 0.49 0.14

Source rock n.d. n.d. n.d. n.d. 0.63 0.72 0.67 1.09 1.69 1.85 0.83 1.12 2.15 2.18 1.75 1.88 1.86 2.04 2.03 2.28 1.96 2.26 2.57 4.01

M N O P Q R R S T T U U U V V V W

E-41533 E-41531 E-41532 E-41543 E-41544 E-41535 E-41534 E-41537 E-41527 E-41528 E-41542 E-41538 E-41541 E-41547 E-41545 E-41546 E-41536

0.69 1.42 0.88 0.79 0.80 2.19 0.65 0.42 0.49 0.98 0.20 1.52 1.07 0.31 0.27 1.66 0.26

0.99 2.01 1.13 0.82 0.69 1.39 0.65 0.47 0.92 1.12 0.34 2 0.97 0.48 0.49 0.41 0.8

1.03 1.83 1.01 1.36 1.46 1.18 1.53 1.57 1.41 1.15 1.76 3.08 1.4 1.63 1.52 1.05 1.59

Crude oil

1.29 2.55 1.37 1.63 1.79 1.48 1.79 1.81 2.24 1.5 1.98 3.31 1.66 2.58 2.04 1.78 1.96

MDR

MDR'

EDR'

C3BTI

n.d. n.d. 0.42 1.18 0.86 1.17 1.38 1.38 1.72 2.35 4.63 28.82

n.d. n.d. 0.30 0.54 0.46 0.54 0.58 0.58 0.63 0.70 0.82 0.00

n.d. n.d. 0.67 0.70 0.61 0.56 0.66 0.69 0.64 0.77 0.82 0.96

0.64 0.46 1.18 n.d. 1.43 2.86 2.66 2.81 4.34 4.28 5.42 n.d.

1.3 1.26 1.21 1.99 2.61 1.07 2.78 3.86 2.44 1.34 5.92 1.66 1.72 5.36 4.19 4.37 2.44

0.57 0.56 0.55 0.67 0.72 0.52 0.74 0.79 0.71 0.57 0.86 0.62 0.63 0.84 0.81 0.81 0.71

0.60 0.66 0.68 0.70 0.74 0.62 0.77 0.77 0.77 0.65 0.81 0.66 0.66 0.86 0.81 0.74 0.69

1.95 1.59 2.69 3.15 3.12 1.87 3.16 3.71 3.45 3.16 3.78 3.12 3.29 4.26 4.40 4.24 3.83

Fig. 9. Map of vitrinite re¯ectance measured on Tithonian source rocks and calculated for crude-oils from the Sonda de Campeche.

In¯uence of maturity on distribution in Tithonian source rocks and crude oils 435

436

D. SantamarõÂ a-Orozco et al.

sociated source rocks. Considering this further, the average C3BTI ratio of the crude oil can be assumed to represent the sum total of oil charges beginning at 0.49% Rc (as presently seen in the northeast) and extending up to at least 1.23% Rr (as documented for drilled source rock; even higher maturities probably occur down ¯ank). This average value will be determined by the volume of oil charge for any given maturity and the concentration of benzothiophenes in the oil at that maturity. The same can be said of the BT/DBT ratio. Because benzothiophenes are most abundant at low maturities (Fig. 5a) it is clear that large volumes of high maturity liquids would be required to change the average oil composition signi®cantly. This seems hard to reconcile when the generative potential of the source rock is considered; in the lower maturity range, HI falls from ca. 700 to 100 mg/g TOC, whereas in the higher maturity range it falls from ca. 100 to 50 mg/g TOC. One way around this dilemma is to consider whether trap formation could have occurred relatively late across the entire area, meaning that the less mature petroleums in the northeast would be trapped synchronously with higher maturity petroleums further to the southwest, with low maturity petroleums formed prior to trap formation in the southwest having been dissipated. This is worthy of further consideration because trap formation, resulting from salt movement and growth faulting, might have taken place as late as the late Miocene whereas petroleum generation could have occurred throughout the Miocene, in part possibly before trap formation, in the southwest Sonda de Campeche (HolguõÂ n, 1987; Angeles-Aquino et al., 1994).

CONCLUSIONS

(1) Tithonian source rocks in the Sonda de Campeche represent an ideal natural laboratory for studying petroleum formation. They contain sulphur-rich Type II kerogen which progressively cracks to form petroleum with increasing maturity, beginning around 0.5% Rr. The increase runs from northeast to southwest in a geographic sense. Kerogen type di€erences, related to organofacies, appear minor. (2) Alkylbenzothiophenes are generated in highest abundance at low maturity (0.35 to 1.09% Rr) whereas the alkyldibenzothiophenes are generated mainly at higher stages of maturity. The relative abundance of speci®c C3-alkylbenzothiophene isomers are especially sensitive to changes in maturity of organic matter. A novel maturity parameter, the C3-benzothiophene index (C3BTI), shows a very good correlation to vitrinite re¯ectance values (Rr30.96, n = 10). MDR', based on alkyldibenzothiophenes, also has a wide dynamic range.

(3) Application of C3BTI and MDR' to the study area reveals several possible scenarios that may explain the ®lling history of reservoirs in the southwest part of the Sonda de Campeche. The fact that concentrations of benzothiophenes and dibenzothiophenes in oils show the same relationships to maturity as do these compounds in source rocks strongly supports the notion of mainly localised vertical migration avenues, possibly in association with a late timing of trap formation. Associate EditorÐJ. S. Sinninghe Damste AcknowledgementsÐWe are grateful to the Managers of Exploration of PEMEX and IMP, especially to Ing. N. Holguõ n-QuinÄones, and Ing. M. A. Ibarra-Romero, for making this study possible. Ing. B. Carrasco-Velazquez's support and advice in the course of this study is acknowledged, as is the technical advice and support of Dr H. Wilkes, Dr M. Radke, H. Willsch, W. Laumer and J. Keller. We would like to thank Dr W. B. Hughes, Dr M. P. Koopmans and Dr J. S. Sinninghe Damste for carefully reviewing the manuscript. REFERENCES

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Appendix A overleaf

Vitrinite Re¯ectance Histograms

APPENDIX A

438 D. SantamarõÂ a-Orozco et al.

In¯uence of maturity on distribution in Tithonian source rocks and crude oils APPENDIX B

De®nition Of Maturity Parameters MDR1=1-MDBT/DBT MDR2,3=2-,3-MDBT/DBT MDR4=4-MDBT/DBT MDR=4-MDBT/1-MDBT MDR' =4-MDBT/(1-MDBT+4-MDBT) EDR'= 4,6-DMBT/(4-EDBT+4,6-DMDBT)

Radke et al. (1982); Radke et al. (1982); Radke et al. (1982); Radke et al. (1986); Radke and Willsch (1994); Radke and Willsch (1994)

MDR and EDR refer to methyldibenzothiophene ratio and ethyldibenzothiophene ratio, respectively. MDBT, EDBT and DMDBT refer to concentrations of isomers belonging to the methyldibenzothiophenes, ethyldibenzothiophenes and dimethyldibenzothiophenes respectively.

439