Hydrocarbon source rock variability within the Austin Chalk and Eagle Ford Shale (Upper Cretaceous), East Texas, U.S.A.

ELSEVIER

International Journal of Coal Geology 34 (1997) 287-305

Hydrocarbon source rock variability within the Austin Chalk and Eagle Ford Shale(Upper Cretaceous), East Texas, U.S.A. C.R. Robison

*

Texaco Exploration and Production Technology Department, 3901 Briar Park Drive, Houston, TX 77042, USA

Accepted 9 July 1997

Abstract The Austin Chalk and Eagle Ford Shale are Upper Cretaceous deposits that extend across Texas from the northeast to southwest. These formations contain organic carbon enriched mudstones and chalks that were deposited during transgressions of the Cretaceous epeiric sea in North America. Recent workers in petroleum geochemistry have demonstrated that these organic enriched rocks possessed attributes common to oil source rocks. The present study of these Austin Chalk and Eagle Ford Shale rocks is from the perspective of organic petrology, and it augments the earlier geochemical work that documented source variability within units of these formations. As with the earlier work, the results of this study show that both formations contain intervals that are, when mature, capable of generating commercial quantities of liquid hydrocarbons. However, this work further revealed that Eagle Ford rocks not only exhibit greater organic carbon contents, but also have greater quantities of oil-prone kerogen (fluorescent amorphinite and exinite) when compared with rocks from the Austin Chalk. These source rock differences relate to levels or degrees of organic preservation. Dysaerobic to oxic depositional settings seem to be more characteristic of the Austin Chalk than of the Eagle Ford Shale. Such oxic environments do not consistently favor the preservation of organic matter. Usually, well-preserved kerogen forms under more anoxic conditions, such as those that occurred during deposition of some Eagle Ford units. These anoxic conditions suggest that the geographically more extensive Eagle Ford Shale is a more important source for oil than is the Austin Chalk. © 1997 Elsevier Science B.V. Keywords: organic petrology and geochemistry; source rock variability; whole-rock pyrolysis; kerogen microscopy; Austin Chalk; Eagle Ford Shale; Upper Cretaceous; East Texas

* Fax: + 1-713-9546911; E-mail: [email protected]/ [email protected] 0166-5162/97/$17.00 © 1997 Elsevier Science B.V. All rights reserved. PII S01 66-5 162(97)00027-X

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1. Introduction For an exploration play or prospect to be viable an estimation of available hydrocarbon resources must be made. To make such an estimation of resource availability, however, means we must have an understanding of the variability within the stratigraphic and geographic distribution of hydrocarbon source rocks for any area of interest. Although we have seen significant advances made over the past two decades in source rock geochemistry, most of these advances center on the identification and characteriza-

East "

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Fig. 1. The areal extent of the Austin Chalk (outcrop belt = dark zone) in Texas (after Montgomery, 1991). The core samples examined in this study came from a well in the general area marked by the dot.

C.R. Robison / lnternational Journal of Coal Geology 34 (1997) 287-305

289

tion of 'average' or 'representative' source rock properties. Little emphasis has been placed on the details of the rock fabric, kerogen macerals, and organic maturity. Only recently has there been an increased emphasis on such details (e.g.; Curiale, 1994; Curiale et al., 1992; Curiale and Lin, 1993; Curiale and Stout, 1993; Katz et al., 1993: Pasley et al., 1991; Pasley et al., 1993; Robison et al., 1994). Naturally, the ultimate aim of such in-depth studies is to better understand the processes controlling variability in quality, quantity, maturity, and character of source rock formations. This petroleum system idea is the basis for the present study of the Austin Chalk and Eagle Ford Shale.

Eagle Ford Shale Approximate Outcrop Belt

Basin

100 miles 160 km

/

Fig. 2. Eagle Ford Shale outcrop belt across east and central Texas and the Austin and Waco sampling areas (after Dawson et al., 1993).

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C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305

2. Purpose of study Both formations possess hydrocarbon source rocks, with the Eagle Ford being the more favorable oil source (Grabowski, 1995). Grabowskrs work gives us a good geochemical prospective into the source character and distribution of organic-rich units within these formations. However, little effort has been made in describing the detailed nature and variability of the solid organic matter (kerogen) from these formations. The present study is an attempt to overcome this situation by looking at the variability of source rock attributes for the formations, as defined by visual kerogen analysis. The petrographic data, considered in conjunction with results from source rock geochemistry (i.e., total organic carbon (TOC), Rock-Eval ® pyrolysis, and maturity analyses), provide the basis for the interpretations presented here. The rocks examined are from a complete conventional core of the Austin Chalk from an East Texas well (Fig. 1) and from outcrops of the Eagle Ford Shale at Austin and Waco, Texas (Fig. 2).

3. Geologic setting Deposition of the Austin Chalk took place during the middle of the Late Cretaceous (Coniacian-Santonian) on a southerly to southeasterly sloping shelf to the Gulf of

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C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305

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Mexico (Grabowski, 1984). The formation outcrops in a belt o f variable thickness from south-central through northeast Texas (Fig. 1). The Austin unconformably underlies the Taylor Marl (Campanian), and usually it has an unconformable contact with the underlying Eagle Ford Shale (Montgomery, 1991). The Austin ranges in thickness from near 61 m to just over 244 m (Hinds and Berg, 1990). Throughout its extent, the Austin consists of chalks (light to dark, often stylolitic); sometimes thin, but dense, micritic limestones; and interbedded dark, calcareous shales, which are most common in the lower part of the formation (Grabowski, 1984; Dawson and Reaser, 1990; Montgomery, 1991). Fig. 3a illustrates a typical Austin outcrop and Fig. 3b illustrates a typical cored section, similar to the one in this study, through the lower chalk in an east Texas well. For this study, the core samples selected are from the dark, calcareous shales. The Eagle Ford Shale reflects deposition o f both siliciclastic and carbonate sediments

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292

C.R. Robison / International Journal o f Coal Geology 34 (1997) 287 305

during an early Late Cretaceous (Cenomanian-Turonian)

t r a n s g r e s s i o n ( D a w s o n et al.,

1993). E x p o s e d u n i t s o f the E a g l e F o r d f o r m a b e l t t h a t is b r o a d in n o r t h e a s t T e x a s , but n a r r o w s as it e x t e n d s to the s o u t h a n d w e s t (Fig. 2). T h e f o r m a t i o n is p r e s e n t b e n e a t h the s u r f a c e t h r o u g h o u t m o s t o f the E a s t T e x a s b a s i n (Surles, 1987; D a w s o n et al., 1993). A t its t y p e locality, the f o r m a t i o n c o n t a i n s a l m o s t 153 m o f b r o w n to b l u i s h - b l a c k c a l c a r e o u s m u d s t o n e s a n d b r o w n i s h - g r a y c a l c a r e o u s s a n d s t o n e s (Surles, 1987). T h e E a g l e F o r d h a s a n u n c o n f o r m a b l e b a s a l c o n t a c t w i t h r o c k s o f the C e n o m a n i a n W o o d b i n e G r o u p in the A u s t i n - W a c o s t u d y area ( D a w s o n et al., 1993). U n c o n f o r m a b l y o v e r l y i n g the E a g l e F o r d t h r o u g h o u t t h e s t u d y area are u n i t s o f the A u s t i n C h a l k . A t W a c o , the E a g l e F o r d is a b o u t 17 m t h i c k ; at A u s t i n , it is a r o u n d 14 m thick. T h e c a l c a r e o u s s h a l e s a m p l e s for this s t u d y c o m e f r o m 4.6 m o f the e x p o s e d L a k e W a c o unit o f the E a g l e F o r d at A u s t i n (Fig. 4) a n d f r o m a b o u t 14 m o f the unit e x p o s e d at W a c o .

Table 1 Organic carbon, sulfur, and whole-rock pyrolysis data, Austin Chalk, East Texas Well Depth (m)

TOC (%)a

Sulfur (%)a

S1 (mg/g)a

S2 (mg/g)a

S 1 + S2 (mg/g)a

S3 (mg/g)a

HI a

OI a

KTR a

7aax

2509.1 2509.4 2510.5 2510.8 2511.2 2511.7 2511.9 2512.3 2512.8 2513.1 2513.4 2513.6 2514.0 2514.5 2514.9 2516.3 2517.0 2517.3 2517.8 2518.4 2519.2 2519.5 2519.7 2519.8

0.81 0.94 1.45 1.21 1.15 0.45 1.37 1.08 0.71 0.71 1.07 0.68 0.66 0.63 0.90 1.57 1.68 0.67 1.00 0.61 1.37 0.93 0.71 1.22

0.76 2.60 3.70 3.15 1.72 1.01 1.80 2.12 1.58 1.50 1.72 1.51 1.59 1.94 2.62 1.89 4.27 2.43 3.47 1.19 1.61 2.70 1.18 2.02

0.12 0.53 0.49 0.18 0.24 nd 0.42 0.10 0.12 nd 0.10 0.13 nd nd 0.16 0.89 1.00 0.12 0.18 nd 0.42 0.24 0.18 0.31

1.96 4.56 4.55 1.17 3.66 nd 4.58 0.38 1.97 nd 0.93 0.88 nd nd 1.45 5.29 6.13 0.86 2.34 nd 2.96 1.53 1.14 3.12

2.08 5.09 5.04 1.35 3.90 nd 5.00 0.48 2.09 nd 1.03 1.01 nd nd 1.61 6.18 7.13 0.98 2.52 nd 3.38 1.77 1.32 3.43

0.17 0.58 0.52 0.77 0.65 nd 0.32 0.65 0.87 nd 0.58 0.55 nd nd 0.50 0.75 0.55 0.50 0.44 nd 0.76 0.56 0.51 0.47

242 485 314 97 318 nd 334 35 125 nd 87 129 nd nd 161 337 364 128 234 nd 216 164 161 256

21 62 35 64 56 nd 23 60 55 nd 54 81 nd nd 55 47 32 74 43 nd 55 60 72 38

0.06 0.10 0.10 0.13 0.06 nd 0.08 0.21 0.06 nd 0.10 0.13 nd nd 0.10 0.14 0.14 0.12 0.07 nd 0.12 0.14 0.14 0.09

438 438 430 438 437 nd 438 446 438 nd 444 439 nd nd 440 434 439 438 439 nd 436 440 442 440

aExplanation: TOC - total organic carbon in weight percentage; Sulfur - total sulfur in weight percentage; nd not determined; pyrolysis usually performed only on samples with 0.70% or greater TOC; Sl - Distillable hydrocarbons present in rock (mg H C / g rock); S2 - Generated hydrocarbons from pyrolysis of kerogen; hydrocarbon generation potential of the rock (mg HC/g rock); S 1 + S z - Total hydrocarbon generation potential (THGP) of the rock (mg HC/g rock); S3 - CO/ generated from kerogen pyrolysis (mg CO 2 / g rock); HI - Hydrogen index (S2/TOC× 100); Ol - Oxygen index (S3/TOC>( 100); KTR - Kerogen transformation ratio, proportion of distillable hydrocarbons to total hydrocarbon potential... ( S j / ( S j + $2)); Tmax - Pyrolysis temperature in °C at which a maximum yield of generated hydrocarbons occurs. -

C.R. Robison / International Journal of Coal Geology 34 (19971 287-305

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Table 2 Organic carbon and whole-rock pyrolysis data, Eagle Ford Shale samples Depth (m) from top

TOC (wt%) a

HI"

Ol a

KTR a

Tn~ax

nd 1.43 1.69 1.60 2.08 2.02 1.70 nd 1.89 2.42 1.59 1.61 1.72 3.01 2.74 1.20

nd 270 330 319 173 323 270 nd 336 46 257 145 465 181 430 376

nd 43 43 45 72 55 78 nd 48 135 65 121 20 125 34 82

nd 0.012 0.019 0.030 0.027 0.011 0.023 nd 0.030 0.087 0.020 0.040 0.034 0.018 0.019 0.022

nd 437 428 415 427 429 421 nd 416 430 415 433 422 440 427 430

0.15 0.13 0.30 11.18 11.32 0.12 0.25 0.19 0.25 11.55 1/.41 11.57 1.08 0.91 0.80 nd 0.80 nd nd 4.50 nd 2.86 3.72

468 359 422 397 534 71 380 540 530 260 293 342 476 274 308 nd 369 nd nd 295 nd 463 427

5 4 5 4 3 9 8 3 3 18 28 19 25 20 25 nd 29 nd nd 171 nd 41 67

0.005 0.004 0.021 0.004 0.007 0.011 0.004 0.003 0.005 0.003 0.002 0.005 0.004 0.003 0.1102 nd 0.003 nd nd 0.010 nd 0.365 0.188

404 411 412 413 412 430 412 412 412 423 430 415 409 416 418 nd 412 nd nd 433 nd 418 426

Sl (rag/g) a

S2 (mg/g)a

S~ --F8 2 (mg/g)a

S3

nd 0.11 0.25 0.34 0.14 0.13 0.14 nd 0.40 0.08 0.13 0.08 1.35 0.08 0.65 0.12

nd 8.86 12.89 11.14 5.00 11.69 5.83 nd 13.04 0.84 6.29 1.93 38.64 4.36 34.21 5.45

nd 8.97 13.14 11.48 5.14 11.82 5.97 nd 13.44 0.92 6.42 2.01 39.99 4.44 34.86 5.57

0.06 0.04 0.50 0.07 0.31 0.01 0.05 0.10 0.17 0.02 0.01 0.05 0.08 0.04 0.02 nd 0.03 nd nd 0.08 nd 18.54 5,41

13.03 9.41 23.45 17.81 43.24 0.89 11.21 31.40 34.55 7.66 4.21 10.20 20.52 11.94 9.67 nd 10.03 nd nd 7.74 nd 32.29 23.40

13.09 9.45 23.50 17.88 43.55 0.90 11.26 31.50 34.72 7.68 4.22 10.25 20.60 11.98 9.69 nd 10.06 nd nd 7.82 nd 50.83 28.81

(rag/g) a

Austin Iocali~ 0 0.31 0.61 0.91 1.22 1.52 1.83 2.13 2.44 2.74 3.05 3.35 3.66 3.96 4.27 4.57

0.84 3.28 3.90 3.49 2.89 3.62 2.16 0.90 3.88 1.79 2.44 1.32 8.30 2.40 7.94 1.45

Waco locality 0 0.61 1.22 1.83 2.14 3.05 3.66 4.27 4.88 5.49 6.10 6.71 7.31 7.92 8.53 9.14 9.75 10.36 10.97 11.58 12.19 12.80 13.41

2.78 2.62 5.55 4.48 8.09 1.25 2.94 5.81 6.51 2.93 1.43 2.98 4.30 4.35 3.14 0.83 2.71 0.68 0.33 2.62 0.24 6.97 5.47

~Refer to explanation following Table 1: for the Eagle Ford Shale, only samples with 1.0 wt% TOC or > were pyrolyzed.

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C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305

4. Materials and methods

The rocks involved in this study include twenty-four conventional core samples of the Austin Chalk from an East Texas well and thirty-nine outcrop samples of Eagle Ford Shale mudstones (sixteen from an exposure of the formation at Austin, Texas, and twenty-three from an outcrop at Waco, Texas). All samples were chipped into about 1 mm pieces. The chipped rock was then divided into sample subsets; one subset for determination of organic enrichment (total organic carbon content - TOC) and source potential yields as revealed by whole-rock pyrolysis (Rock-Eval®), the other sample subset was for kerogen microscopy. All samples examined for organic richness and source potential were mechanically ground to powder (200-mesh). A split of the powdered material of each sample was treated with dilute hydrochloric acid to dissolve carbonate minerals, dried, and then

Table 3 Kerogen maceral compositions of Austin Chalk samples Depth (m)

2509.1 2509.4 2510.5 2510.8 2511.2 2511.7 2511.9 2512.3 2512.8 2513.1 2513.4 2513.6 2514.0 2514.5 2514.9 2516.3 2517.0 2517.3 2517.8 2518.4 2519.2 2519.5 2519.7 2519.8

TOC a (wt%)

0.81 0.94 1.45 1.21 1.15 0.45 1.37 1.08 0.71 0.71 1.07 0.68 0.66 0.63 0.90 1.57 1.68 0.67 1.00 0.61 1.37 0.93 0.71 1.22

Maceral Compositiona (vol%) FIAm

Exin

% Oil Prone

NFIAm

Vit

Inert

12 26 16 15 12 14 14 5 17 14 5 3 10 1 5 11 25 15 21 7 17 12 6 15

16 34 32 33 27 35 25 24 34 26 24 13 20 32 28 25 28 35 24 22 30 32 26 32

28 60 48 48 39 49 39 29 51 40 29 16 30 33 33 36 53 50 45 29 47 44 32 47

44 23 27 29 42 44 55 55 34 46 46 70 62 56 56 49 41 30 44 67 40 46 58 36

19 6 7 7 11 2 5 7 11 8 19 10 4 3 5 8 3 12 5 1 3 2 4 8

9 11 18 16 8 5 1 9 4 6 6 4 4 8 6 7 3 8 6 3 10 8 6 9

aExplanation: TOC - Weight percentage of total organic carbon; FIAm - Fluorescent amorphinite (fluorescent structureless kerogen); Exin - Exinite (spores, pollen, cuticle, resins, etc.); Oil Prone - The total of those constituents (fluorescent amorphinite and exinite) that are prone to the generation of oil when they become mature; NFIAm - Nonfluorescent amorphinite (nonfluorescent structureless kerogen); Vit - Vitrinite (structured kerogen derived from wood); Inert - Inertinite (black opaque kerogen).

C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305

295

combusted in a LECO Carbon/Sulfur Analyzer for TOC and sulfur contents. Some of the remaining portion of each powdered sample was subjected to Rock-Eval ® whole-rock pyrolysis after the procedure described by Espitali6 et al. (1977). Table 4 Kerogen Maceral compositions for Eagel Ford Shale samples Depth (m) from top

TOC a (wt%)

Maceral composition (vol%) F1Am

Exin

% Oil Prone

NFIAm

Vit

Inert

0.84 3.28 3.90 3.49 2.89 3.62 2.16 0.90 3.88 1.79 2.44 1.32 8.30 2.40 7.94 1.45

34 43 44 40 42 40 40 36 40 25 55 60 67 65 46 43

20 22 30 25 25 24 30 16 16 14 10 16 21 20 27 23

54 65 74 65 67 64 70 52 56 39 65 76 88 85 73 66

34 22 10 25 20 20 14 42 32 51 25 20 8 10 15 17

8 5 8 2 5 8 t0 4 10 8 8 4 2 2 11 12

4 8 8 8 8 8 6 2 2 2 2 0 2 3 1 5

2.78 2.62 5.55 4.48 8.09 1.25 2.94 5.81 6.51 2.93 1.43 2.98 4.30 4.35 3.14 0.83 2.71 0.68 0.33 2.62 0.24 6.97 5.47

38 42 40 37 37 24 56 52 30 44 40 41 34 34 56 35 60 42 44 40 38 35 54

20 20 15 15 18 19 18 19 28 20 16 15 22 24 18 2(1 25 24 12 30 18 20 20

58 62 55 52 55 43 74 71 58 64 56 56 56 58 74 55 85 66 56 70 56 55 74

22 23 25 33 37 47 18 20 22 16 32 30 36 28 21 20 10 18 34 20 26 25 16

18 11 15 10 6 6 4 7 16 20 12 10 8 10 4 18 4 12 8 6 12 15 8

2 4 5 5 2 3 4 2 4 0 0 4 0 4 1 7 1 4 2 4 6 5 2

Austin locali~ 0 0.31 0.61 0.91 1.22 1.52 1.83 2.13 2.44 2.74 3.05 3.35 3.66 3.96 4.27 4.57

Wacolocali~ 0 0.61 1.22 1.83 2.14 3.05 3.66 4.27 4.88 5.49 6.10 6.71 7.31 7.92 8.53 9.14 9.75 10.36 10.97 11.58 12.19 12.80 13.41

"Refer to Table 3 for an explanation of terms.

C.R. Robison / lnternational Journal c~fCoal Geology 34 (1997) 287-305

296

The other sample subsets of chips from both core and outcrop material were demineralized with hydrochloric and hydrofluoric acids following standard kerogen isolation procedures (Combaz, 1980). Kerogen macerals were separated from any remaining mineral matter by heavy liquid separation using zinc bromide (specific gravity 1.85-1.90). Kerogen strew slides were prepared from the concentrated kerogen. The mounting medium used is a nonfluorescent synthetic resin. Kerogen microscopy was performed in both transmitted white light and blue-light fluorescence with a Nikon Microphot-FXA microscope. Five hundred particles per slide were counted. Five main maceral classes were recognized: fluorescent amorphinite (F1Am), exinite (Exin), nonfluorescent amorphinite (NF1Am), vitrinite (Vit), and inertinite (Inert). 5. Results and discussion

5.1. Organic enrichment and source potential

Tables 1-4 and Figs. 5-12 reveal the general source rock character of the Austin Chalk and the Eagle Ford Shale samples examined as a part of this study. Organic

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C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305 100

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Total Organic Carbon (wt %) Fig. 6. Total organic carbon versus total hydrocarbon generation potential (THGP, S 1 + S 2 mg H C / g rock) separates samples with source character from nonsource samples. In general, good source rocks have TOCs from 1 to 2 wt% and THGPs from 5 to 20 mg H C / g rock; whereas excellent source rocks usually exhibit TOCs > 2 wt% and THGPs > 20 mg H C / g rock (Bissada et al., 1993).

enrichment, as determined by total organic carbon content (TOC), is greater for the Eagle Ford samples than it is for the Austin Chalk samples (Tables 1 and 2; Fig. 5). Austin Chalk samples have TOC values ranging from 0.5 to nearly 2.0 wt%; and the Eagle Ford samples have TOC contents ranging from about 1.0 to nearly 10.0 wt%. Fig. 5 is based on the comparison of total organic carbon content with total sulfur content and demonstrates the range of marine depositional conditions for the source intervals examined. The TOC levels are within acceptable limits of organic enrichment for hydrocarbon source rocks (TOC > 1.0%, Bissada, 1982). However, a rock must also contain organic matter capable of generating hydrocarbons to be considered a source rock, and this was determined here by using the total hydrocarbon generation potentials (THGPs) of the samples as illustrated in Fig. 6. Favorable source rocks occur in both formations based on their THGPs as determined by pyrolysis yields of S 1 (free hydrocarbons in a rock sample) plus S2 (hydrocarbons liberated from kerogen during pyrolysis). Additionally, the percentages of oil-prone kerogen (fluorescent amorphinite plus exinite) present in specific units of each formation provide a qualitative indication

298

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of source rock potential (Figs. 10 and 12). Samples from the Austin Chalk have lower total hydrocarbon generation potentials than do rocks from the Eagle Ford Shale. More than half of the Austin Chalk samples exhibit low to marginal THGPs (0.48 to 2.5 mg H C / g rock); whereas, the THGP's of the Eagle Ford Shale samples range from about 1 to over 50 mg H C / g rock, which gives them a good to excellent hydrocarbon source potential (Fig. 6). The Tissot, or modified van Krevelen, diagram depicted in Fig. 7 distinguishes hydrogen-rich from hydrogen-lean organic matter. As a result, the oil proneness of organic matter can be evaluated. Most of the Austin and Eagle Ford rocks contain a mixture of type II kerogen (which contains largely hydrogen-enriched kerogen such as fluorescent amorphous material, alginite, and exinite) and type III kerogen (which is composed mostly of hydrogen-poor humic organic matter such as vitrinite and oxidized amorphous material). Thus, these rocks are both oil and gas prone, with the Eagle Ford Shale from the Waco locality as perhaps more oil prone than the other samples. Some of the Austin rocks, as well as some Eagle Ford rocks from the Austin outcrop, plot along the mean line for type III kerogen, which indicates that they are largely gas prone. A

299

C.R. Robison / international Journal of Coal Geology 34 (1997) 287-305 480

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i 0.60

Fig. 8. Sourcerock maturity levels as indicated by a crossplot of the kerogentransformationratio and Tma~ values from Rock-Evalpyrolysis.

couple of samples, one each from the Austin and the Eagle Ford (Austin site) plot well below the type III mean line, which suggests that they contain considerable amounts of hydrogen-poor kerogen. This condition is supported by the petrographic data (Tables 3 and 4). The kerogen in both the Austin Chalk sample (core from 2512.3 m) and the Eagle Ford sample (Austin locality 8713 B-023) is predominantly non-fluorescent amorphinite, which is at best only gas-prone. Yet, overall, the kerogen of both formations is mainly a type II marine kerogen to a mixed type II and III (humic) kerogen (Fig. 7). With these rocks, however, the tendency toward type III kerogen is related to how much hydrogen-lean, non-fluorescent amorphinite they contain, rather than how much humic kerogen of a vitrinitic nature they possess. Fig. 8 is a plot of the Rock-Eval ® pyrolysis parameters kerogen transformation ratio (KTR) and Tmax. The KTR is the proportion of free hydrocarbons (S l) in a rock to the rock's total generation potential (S~ + S2, where the S2 is the amount of hydrocarbons generated from the pyrolysis of kerogen). If a rock is free of contamination, the KTR can be used as an indicator of source rock maturity. Tm,x is the pyrolysis temperature (in °C) at which the maximum yield of generated hydrocarbons occurs, and it increases with

300

C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305 Austin Chalk, East T e x a s Well

Eagle F o r d Sh., A u s t i n L o c a l i t y

Maceral Composition (vol. %)

Maceral Composition (%)

0%

25%

50%

0% 0

2510.5

.............

I

251o.6 2511.2

............. .....................

I

031

[

061

2511 7

' " ' " " " ' ........

I

..................

2513.1

~ 2513.4~

......................

I

2513.6

E

25149 t 2516.3 t 25170 t

1

25173 251718 I

I

0%

25%

50%

75%

100%

IIIlllll

E

IIIIII

1.83

2.44

I I I I

2.74

I

3.66

I

............................ ............... ....................

I I

2519.7 t

..........................

I

I

(a)

IIIIIIIJll

IIIIIII

.......................... ........................ ................

..................

IO(P/~

I

1.52

I

2518.4 12519.2 t 25195~ 2519.8 t

75%

I

12 2

........................

................. ....................

50%

I

091

2.13

2514,0 ~D. 2514.5 1-

25%

"

z

251192512.3 .....',',',',',',11',',11',',',11',',2'""] 2512.8

Maceral Composition (%)

75% 100%

~

2509.1 2509.4

E a g l e Ford Sh., W a c o Locality

111 ~Ill[lT~IlIIIlm

• Inert

E

4.88 " 5.49 6.10 "

t'lVit [ ] N FIArn

6.71 " 7.31 "

•Exin

3.05 3.36

1;73561

..........:: ]

•FlAre

10.97 1158

3.96 427

Ilhl

457

Ilhl

(b)

1219 1280 1341

(c)

Fig. 9. Distribution of kerogen maceral types in samples of the (a) Austin Chalk, (b) Eagle Ford Shales (Austin locality), and (c) Eagle Ford Shale (Waco Locality). (Inert = inertinitic, Vit = vitrinitic. Exin = exinitic, NF1Am = nonfluorescent amorphinite, and FIAm = fluorescent amorphinite).

increasing maturation. In general, the potential source rocks from both formations have KTRs that are often less than 0.2 and Tmax values ranging from 435°C to a little more than 440°C (Fig. 8; Tables 1 and 2). These values mark the onset of hydrocarbon generation and expulsion (i.e, the top of the 'oil window'). None of the rocks examined during the course of this study is mature enough to have both generated and expelled significant quantities of hydrocarbons. 5.2. Visual kerogen analyses

The analyzed core interval of the Austin Chalk was about 10.5 m thick and was from between 2509 and 2520 m in the East Texas well. Fig. 9a shows the general distribution of various kerogen macerals over the 10.5 m interval. Nonfluorescent to weakly fluorescent amorphinite is the most abundant kerogen maceral in most samples. Oil-prone kerogen, which consists of the total percentages of fluorescent amorphous material and exinite (Fig. 10, column on the righ0, is most frequently present in the form of granular and often finely disseminated fluorescent amorphinite and exinite, and only rarely does the concentration of oil-prone kerogen exceed 50% (Table 3; Fig. 9a). In the Austin Chalk samples, exinites consist predominately of small algal spores, dinoflagellate cysts, minor amounts of terrestrial spores/pollen, and a considerable amount of palynomorph fragments (mostly broken dinoflagellate cysts). There are shifts in the concentrations of

C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305

YOC (wl. %) 0

5

301

THGP*($1+$2) Hydrogen Index Oil-Prone Kerogen** (rng HC/grock) (S2/TOC x100) (%) 10

1

10

1000

400

8000

50

100

2508

2512

J~ a

2516

2520

Austin Chalk, East Texas Well Fig. 10. Comparative profiles of source rock attributes for the Austin Chalk, East Texas Well. ( * THGP = total hydrocarbon generation potential; * * Oil-Prone kerogen = fluorescent amorphinite plus exinite).

the various kerogen macerals over the 10.5 m interval. However, there are no important changes in the kerogen that relate to major changes in the kinds of organisms that contributed to the organic matter that was deposited. The shifts seem to be connected instead with just how much material was actually available for deposition because of fluctuations in the environment and the potential for preservation of this organic material. The Eagle Ford Shale samples from both the Austin and Waco localities are, compared with the Austin Chalk, dominated by fluorescent amorphinite (Fig. 9b, c). These rocks have less exinite than the Austin Chalk samples, but the Eagle Ford from both study sites contains much more fluorescent amorphinite, so it is not unusual for oil-prone kerogen to make up 60-75% of the kerogen in any given Eagle Ford sample (Table 4; Fig. 9b, c). The richest intervals sampled at both sites have oil-prone kerogen concentrations from 80-85%. These units are usually from the transgressive systems tract of the section measured by Dawson et al. (1993). Overall, the various kerogen macerals in the Eagle Ford samples are similar to those in samples of the Austin Chalk. That is, the kerogen in both formations is basically from the same type of organisms, and little, if any, permanent change in biota contributing to the sedimentary organic matter took place during either Austin Chalk or Eagle Ford times.

C.R, Robison / lnternational Journal of Coal Geology 34 (1997) 287-305

302

5.3. Source variability Fig. 10 shows variability trends in Austin Chalk samples for organic carbon contents, total hydrocarbon generation potentials, hydrogen indices, and oil-prone kerogen concentrations. In general, the profiles are similar with fluctuations occurring at similar depths. These data suggest that minor changes in organic facies have occurred. However, the overall kerogen type seems to be rather consistent over the 10.5 m of core studied; thus, the fluctuations seen in the plotted data may more simply reflect minor transgressive and regressive phases. This interpretation is supported by the regular oscillation of hydrogen versus oxygen enrichment in the kerogen, a condition consistent with minor, but frequent, changes in depositional environment. Figs. 11 and 12 are plotted profiles comparing organic carbon contents, total hydrocarbon generation potentials, hydrogen indices, and oil-prone kerogen concentrations for the Eagle Ford Shale from the two outcrop localities-Austin and Waco. Again, the profiles are broadly comparable. As in the case of the Austin Chalk, the general overall character of the kerogen remains the same over the sampled intervals. The kerogen composition does not reflect major changes in the source of the kerogen available for deposition. The shifts are probably related to minor transgressions and regressions, as they are in the Austin Chalk core.

TOC (wt. %) 0 o

5 \

'

I

'

THGP* ($1+$2) Hydrogen IndexOiI-Prone Kerogen** (%) (rag HC/g rock) (S2/TOC x100) 50 100 10 1 10 1000 400 8000 '""1

'"'1

'"'--

'

I

'

'

~

Highstend Systems

Tract

E

2

m

"i.j

~

m

~K maximum

flooding

surface m

condensed

section (?)

/

'~

c

.o_ p_ 3

m

_

n

I

I

,

,,,-J ,,,-J ,,,,,,

Transgre/~si~

_

I

I

I

I

I

,

Eagle Ford Shale, Austin Locality Fig. 11. Comparative profile of source rock attributes for the Eagle Ford Shale, Austin locality. ( * THGP = total hydrocarbon generation potential; * * Oil-Prone kerogen = fluorescent amorphinite plus exinite).

C.R. Robison / lnternational Journal of Coal Geology 34 (1997) 287-305

TOC (wt. %) 0

5

303

THGP* ($1 +$2) Hydrogen Index OiFProne Kerogen** (mg HC/g rock) (S2/TOC x 100) (%) 10 1 10 1000 400 8000 50 100

0

E v

6

C "~

8

10

12

14

Eagle Ford Shale, Waco Locality Fig. 12. Comparative profiles of source rock attributes for the Eagle Ford Shale, Waco locality. ( * THGP = total hydrocarbon generation potential; * * Oil-Prone kerogen = fluorescent amorphinite plus exinite).

The subtle transgressive and regressive phases are reflected in differences in the preservation of kerogen. Such conditions for the Eagle Ford Shale can be seen in Fig. l 1 between 3 to 4.6 m in the measured section. According to Dawson et al. (1993), the interval represents a transgressive systems tract. Within this 1.6 m Eagle Ford Shale interval are the richest source units in the section. These enriched zones are preceded as well as followed by zones much reduced in organic carbon contents, generation potentials, hydrogen indices, and oil-prone kerogen contents. The kerogen changes are seen in shifts from high relative amounts of fluorescent amorphinite to high amounts of non-fluorescent amorphinite. The increase in the latter kerogen type is the result of organic matter being deposited during dysaerobic to oxic periods of minor regressions during an overall major transgressive period. The petrographic variability observed in the Austin Chalk and Eagle Ford Shale is consistent with the geochemical variability reported for these formations by Dawson et al. (1993) and Grabowski (1995). As suggested by these authors, this variability has significant implications for the source rock potential, and thus the possible oil yields from the formations when they are at the peak of generation and expulsion. In general, the more favorable source character of the Eagle Ford Shale and its more widespread occurrence argue in favor of it being a more productive source in East Texas than the Austin Chalk.

304

C.R. Robison / lnternational Journal of' Coal Geology 34 (1997) 287-305

6. Conclusions The results of this petrographic study of organic rich rocks from the Austin Chalk and Eagle Ford Shale of east Texas are generally consistent with results from earlier geochemical source rock studies of these formations (refer to Grabowski, 1995, 1984, 1981; Dawson et al., 1993; Surles, 1987; Hunt and McNichol, 1984). The following conclusions came from the study: (1) The general kerogen maceral types appear to be fairly constant, but percentages of hydrogen-rich fluorescent amorphinite is nearly three times as abundant in the Eagle Ford Shale as it the Austin Chalk. (2) Although variations occur in both geochemical source rock parameters as well as in the relative abundances of the five kerogen macerals described from both formations, these variations are most likely connected to changing conditions of preservation and the availability of organic matter for burial. (3) Much of the amorphous kerogen (fluorescent and non-fluorescent) that dominated both the Austin Chalk and the Eagle Ford Shale samples examined here tends to be granular and is finely divided. These particular features are characteristic of kerogen recovered from rocks deposited under dysaerobic to oxic conditions. The many small fragments of exinite in samples from both formations is also consistent with considerable mechanical degradation of the organic matter during its transport to the site of deposition. This condition indicates a much higher energy setting than is usual for a strictly anoxic depositional environment. (4) Greater amounts of hydrogen-rich exinite in the form of dinoflagellate cysts, fragments of these cysts, other small algal spores, and a few terrestrial palynomorphs are present in both formations than had been previously reported. (5) Subtle shifts in organic facies within source units of both the Austin Chalk and Eagle Ford Shale were probably caused by minor regressions during major transgressive phases. (6) The Eagle Ford exhibits the best source rock character for oil, based on its geochemical and organic petrographic attributes. Because of this, it is probably more important as an oil source in East Texas fields than is the Austin Chalk.

Acknowledgements I thank B.J, Katz and V.D. Robison for providing the Eagle Ford Shale samples and some of the organic carbon and pyrolysis data. I also thank Texaco Inc. for allowing me to publish this work, which benefitted from critiques by two anonymous reviewers.

References Bissada, K.K., 1982.Geochemicalconstraintson petroleumgenerationand migration- A review,Proceedings ASCOPE '81, pp. 61-87. Bissada, K.K,, Elrod, L.W., Robison,C.R., Darnell, L.M., Szymczyk,H.M., Trostle,J.L., 1993. Geochemical

C.R. Robison / International Journal of Coal Geology 34 (1997) 287-305

3(15

inversion - A modern approach to inferring source-rock identity from the characteristics of accumulated oil and gas. Energy Explor. Exploit. 11 (3/4), 295-328. Combaz, A., 1980. Les krrog~nes vus au microscope, in: Durand, B. (Ed,), Kerogen: Insoluble Organic Matter from Sedimentary Rocks, Editions Technip, Paris, pp. 55-112. Curiale, J.A., 1994. High-resolution organic record of Bridge Creek deposition, northwest New Mexico. Org. Geochem. 21,489-507. Curiale, J.A., Cole, R.D., Witmer, R.T., 1992. Application of organic geochemistry to sequence stratigraphic analysis. Four Corners Platform Area, New Mexico, U.S.A. Org. Geochem. 19, 53-75. Curiale, J.A., Lin, R., 1993. Tertiary deltaic and lacuatrine organic facies: Comparison of biomarker and kerogen distribution. Org. Geochem. 17, 785-803. Curiale, J.A., Stout, S.A., 1993. Monitoring tectonically controlled marine to lacustrine transitions using organic facies - Ridge basin, California, USA, Chem. Geol. 109, 239-268. Dawson, W.C., Katz, B.J., Liro, L.M., Robison, V.D., 1993. Stratigraphic and geochemical variability: Eagle Ford Group, East-Central Texas, in: Armentrout, J.M., Bloch, R.. Olson, H.C. (Eds.), Rates of Geologic Processes, GCSSEPM Foundation 14th Ann. Research Conf., Dec. 5-8. 1993, pp. 19-28, Dawson, W.C., Reaser, D.F., 1990. Trace fossils and paleoenvironments of lower and middle Austin Chalk (Upper Cretaceous), north-central Texas. Trans. GCAGS 40, 161-173. Espitalir, J., Laporte, J,L., Madec, M., Marquis, F., Leplat, P., Poulet, J., Boutefeu, A., 1977. Methode rapide de caracterisation des roches meres de leur potentiel petrolier et de leur degre d'evolution. Rev. Inst. Ft. Pet. 32, 23-42. Grabowski, G.J. Jr., 1981. Source-rock potential of the austin Chalk, Upper Cretaceous, Southeastern Texas. Trans. GCAGS 31, 105-113. Grabowski, G.J., Jr., 1984. Generation and migration of hydrocarbons in Upper Cretaceous Austin Chalk~ south-central Texas, in: Palacas, J.G. (Ed.), Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks, AAPG Studies in Geology #18, pp. 97-115. Grabowski, G.J., Jr., 1995. Organic-rich chalks and calcareous mudstones of the Austin Chalk and Eagleford Formation, south-central Texas, USA, in: Katz, B.J. (Ed.), Petroleum Source Rocks, Springer-Verlag, Berlin, pp. 205-234. Hinds, G.S., Berg, R.R., 1990. Estimating organic maturity from well logs, Upper Cretaceous Austin Chalk, Texas Gulf Coast. Trans. GCAGS 40, 295-300. Hunt, J.M., McNichol, A.P., 1984. The Cretaceous Austin Chalk of South Texas - A Petroleum source rock, in: Palacas, J.G. (Ed.), Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks. AAPG Studies in Geology #18, pp. 117-125. Katz, B.J., Breaux, T.M. Coiling, E.L., Darnell, L.M., Elrod, L.W., Jorjorian, T., Royle, R.A., Robison V.D., Szymczyk, H.M., Trostle, J.L., Wicks, J.P., 1993. Implications of Stratigraphic variability of source rocks, in: Katz, B.J., Pratt, L.M. (Eds.), Source Rocks in a Sequence Stratigraphic Framework, AAPG Studies in Geology #37, pp. 5-16. Montgomery, S., 1991. Horizontal drilling in the Austin Chalk Part 1, Geology, drilling history and field rules. vol. 7(3), Petroleum Frontiers, 44 pp. Pasley, M.A., Gregory, W.A., Hart, G.F., 1991. Organic matter variations in transgressive and regressive shales. Org. Geochem. 17, 483-509. Pasley, M.A., Riley, G.W., Nummedal, D., 1993. Sequence stratgraphic significance of organic matter variations: Example from the Upper Cretaceous Mancos Shale of the San Juan Basin, New Mexico, in: Katz, B.J., Pratt, L.M. (Eds.), Source Rocks in a Sequence Stratigraphic Framework, AAPG Studies in Geololgy #37, pp, 221-241. Robison, V.D., Liro, L.M., Robison, C.R., Dawson, W.C., Russo, J.W., 1994. Integrated geochemistry, organic petrology, and sequence stratigraphy of the Triassic Sbubilk Formation, Tenneco Phoenix # 1 well, North Slope, Alaska, Proc., llth Ann. Mtg., The Society for Organic Petrology, vol. I1. pp. 87-89 (extended abstr.) Surles, M.A. Jr., 1987. Stratigraphy of the Eagle Ford Group (Upper Cretaceous) and its source-rock potential in the East Texas Basin. Baylor Geol. Stud. Bull. 45, 57.